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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549



FORM 10-K



(Mark One)    

ý

 

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

For the fiscal year ended December 31, 2013

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 o 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 ý 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. ý

         Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See 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 their affiliates, for this purpose, as if they were affiliates of the registrant) as of June 28, 2013 was approximately $637,063,749 based on a price per common unit of $39.90, the price at which the common units were last sold as reported on the New York Stock Exchange on such date.

         As of March 11, 2014, 27,430,563 common units were outstanding.

   


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TABLE OF CONTENTS

 
   
   

PART I

 

 

   

Items 1. and 2.

 

Business and Properties

  4

Item 1A.

 

Risk Factors

  20

Item 1B.

 

Unresolved Staff Comments

  46

Item 3.

 

Legal Proceedings

  46

Item 4.

 

Mine Safety Disclosures

  48

PART II

 

 

 
 

Item 5.

 

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

  49

Item 6.

 

Selected Financial Data

  50

Item 7.

 

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

  52

Item 7A.

 

Quantitative and Qualitative Disclosures about Market Risk

  83

Item 8.

 

Financial Statements and Supplementary Data

  85

Item 9.

 

Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

  85

Item 9A.

 

Controls and Procedures

  85

Item 9B.

 

Other Information

  89

PART III

 

 

 
 

Item 10.

 

Directors, Executive Officers and Corporate Governance

  90

Item 11.

 

Executive Compensation

  94

Item 12.

 

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

  125

Item 13.

 

Certain Relationships and Related Transactions, and Director Independence

  127

Item 14.

 

Principal Accounting Fees and Services

  131

PART IV

 

 

 
 

Item 15.

 

Exhibits and Financial Statement Schedules

  133

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Forward-Looking Statements

        Some of the information contained in this Annual Report on Form 10-K may contain forward-looking statements. Forward-looking statements 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. Although we believe these forward-looking statements are reasonable as and when made, there may be events in the future that we are not able to predict accurately or control, and there can be no assurance that future developments affecting our business will be those that we anticipate. Additionally, all statements concerning our expectations regarding future operating results are based on current forecasts for our existing operations and do not include the potential impact of any future acquisitions. The factors listed under "Risk Factors," as well as any cautionary language in this report, describe the known material risks, uncertainties and events that may cause our actual results to differ materially from the expectations we describe in our forward-looking statements. Additional factors or events that may emerge from time to time, or those that we currently deem to be immaterial, could cause our actual results to differ, and it is not possible for us to predict all of them. You are cautioned not to place undue reliance on the forward-looking statements contained herein. The following factors are among those that may cause actual results to differ materially and adversely from our forward-looking statements:

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

    Our crude oil sales could be adversely affected by, among other things, unanticipated changes in the crude oil market structure, grade differentials and volatility (or lack thereof), changes in refiner demand, severe weather conditions, significant changes in prices and interruptions in rail transportation services and other necessary services and equipment, such as railcars, trucks, loading equipment and qualified drivers.

    We depend upon marine, pipeline, rail and truck transportation services for a substantial portion of our logistics business in transporting the products we sell. A disruption in these transportation services could have an adverse effect on our financial condition, results of operations and cash available for distribution to our unitholders.

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

    Warmer weather conditions could adversely affect our home heating oil and residual oil sales.

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

    Our results of operations are affected by the overall forward market for the products we sell.

    Our business could be affected by a range of issues, such as changes in commodity prices, energy conservation, competition, the global economic climate, movement of products between foreign locales and within the United States, changes in refiner demand, weekly and monthly refinery output levels, changes in local, domestic and worldwide inventory levels, changes in safety regulations, seasonality and supply, weather and logistics disruptions.

    Increases and/or decreases in the prices of the products we sell could 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.

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

    The condition of credit markets may adversely affect us.

    Our bank credit agreement and the indentures governing our senior notes contain operating and financial covenants, and our credit agreement contains borrowing base requirements. A failure to comply with the operating and financial covenants in our credit agreement, the indentures and any future financing agreements could impact our access to bank loans and other sources of financing and restrict our ability to finance future operations or capital needs or to engage in, expand or pursue our business activities.

    A significant increase in interest rates could adversely affect our ability to service our indebtedness.

    Our gasoline 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.

    Adverse developments in the areas where we conduct our business 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 businesses 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.

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        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.

        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. 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.


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 master limited partnership formed in March 2005. As of December 31, 2013, we had the following wholly-owned subsidiaries: Global Companies LLC, Glen Hes Corp., Global Montello Group Corp. ("GMG"), Chelsea Sandwich LLC, Global Energy Marketing LLC, Alliance Energy LLC, Bursaw Oil LLC, GLP Finance Corp., Global Energy Marketing II LLC, Global CNG LLC and Cascade Kelly Holdings LLC. Our general partner manages our operations and activities and employs our officers and substantially all of our personnel, except for our gasoline station and convenience store employees and certain union personnel who are employed by GMG.

        We are a midstream logistics and marketing company. We are one of the largest distributors of gasoline (including gasoline blendstocks such as ethanol and naphtha), distillates (such as home heating oil, diesel and kerosene), residual oil and renewable fuels to wholesalers, retailers and commercial customers in the New England states and New York. We also engage in the purchasing, selling and logistics of transporting domestic and Canadian crude oil and other products via rail, establishing a "virtual pipeline" from the mid-continent region of the United States and Canada to the East and West Coasts for distribution to refiners and other customers. We own, control or have access to one of the largest terminal networks of refined petroleum products and renewable fuels in Massachusetts, Maine, Connecticut, Vermont, New Hampshire, Rhode Island, New York, New Jersey and Pennsylvania (collectively, the "Northeast"). We also own and control terminals in North Dakota and Oregon that extend our origin-to-destination capabilities. We are a major multi-brand gasoline distributor and, as of December 31, 2013, had a portfolio of approximately 900 owned, leased and/or supplied gasoline stations primarily in the Northeast. We receive revenue from retail sales of gasoline, convenience store sales and gasoline station rental income. We are also a distributor of natural gas and propane.

Operations and Segments

        Collectively, we sold approximately $19.4 billion of refined petroleum products, renewable fuels, crude oil, natural gas and propane for the year ended December 31, 2013. In addition, we had other revenues of approximately $146.5 million, primarily from convenience store sales at our directly operated stores and rental income from dealer leased or commission agent leased gasoline stations. As of December 31, 2013, we owned, leased or maintained dedicated storage facilities at 26 petroleum product bulk terminals, each with the capacity of more than 50,000 barrels, including 22 refined product terminals located throughout the Northeast. These terminals are supplied primarily by marine transport, pipeline, rail and/or truck and collectively have approximately 10.2 million barrels of storage capacity. In addition to refined products, we have storage capacity at our Albany, New York, Clatskanie, Oregon and North Dakota terminals to store crude oil, at an Albany, New York terminal to store propane and at select locations to store renewable fuels. In Columbus, North Dakota we constructed a 100,000 barrel storage tank and a truck offloading facility in 2012 and a 170,000 barrel storage tank in 2013 used as part of the development of that location as a hub for the gathering, storage, transportation and marketing of crude oil and other products. In Beulah, North Dakota, through Basin Transload, LLC ("Basin Transload"), we constructed two 140,000 barrel storage tanks and a truck offloading facility used as part of the development of that location as a hub for the gathering, storage, transportation and marketing of crude oil and other products. We also have

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throughput and exchange agreements at numerous bulk terminals and inland storage facilities. We lease a fleet of rail cars which are utilized in the transporting of crude oil and other products by rail. In addition, we have storage agreements at several of our terminals granting storage rights to third parties for which we receive a fee.

        In September 2013, our Columbus, North Dakota transloading facility began receiving crude oil from a newly completed seven-mile pipeline lateral connection constructed by Tesoro Logistics, which transports crude oil from various gathering points along the Tesoro High Plains Pipeline System. Also, in 2013, we completed construction in Albany, New York of a new rail-fed propane storage and distribution facility near our existing terminal in Albany, New York and in April, we began receiving and distributing product from the facility. The 540,000-gallon facility can source propane directly from Midwest and Canadian regional sources via single line haul on Canadian Pacific as well as from the East Coast. In addition, construction of a compressed natural gas loading station in Bangor, Maine was completed, and we have established a multi-year agreement with Bangor Gas to supply natural gas to the facility.

        We purchase refined petroleum products, renewable fuels, crude oil, natural gas and propane primarily from domestic and foreign refiners and ethanol producers, crude oil producers, major and independent oil companies and trading companies, and we sell these products in three reporting segments: (i) Wholesale, (ii) Gasoline Distribution and Station Operations and (iii) Commercial which are discussed below. In 2013, our Wholesale sales accounted for approximately 78% of our total sales, and our Gasoline Distribution and Station Operations and Commercial sales accounted for17% and 5%, of our total sales, respectively.

    Wholesale

        We engage in the logistics of gathering, storage, transportation and marketing of refined petroleum products, renewable fuels, crude oil and propane. In February 2013, we acquired a 60% membership interest in Basin Transload, which operates two transloading facilities (which are facilities used for transferring product shipments from one mode of transportation to another) in Columbus and Beulah, North Dakota for crude oil and other products. Also in February 2013, we acquired 100% of the membership interest in Cascade Kelly Holdings LLC ("Cascade Kelly"), which owns a West Coast crude oil transloading and ethanol manufacturing facility near Portland, Oregon. In January 2013, we signed a five-year contract with Phillips 66 under which we use our storage, rail transloading, logistics and transportation system to deliver crude oil from the Bakken region to Phillips 66's Bayway, New Jersey refinery.

        We own, control or have access to one of the largest terminal networks of refined petroleum products and renewable fuels in the Northeast. We also own and control terminals in North Dakota and Oregon that extend our origin-to-destination capabilities. Our strategically located terminal assets, logistics capabilities, transloading facilities and access to railroad and barge transportation provide a "virtual pipeline" solution for the transportation of crude oil, renewable fuels and other products from the mid-continent region of the United States and Canada to the East and West Coasts.

    Gasoline Distribution and Station Operations

        As of December 31, 2013, we had a portfolio of approximately 900 owned, leased and/or supplied gasoline stations primarily in the Northeast. In September 2010, we completed the acquisition from ExxonMobil Corporation "(ExxonMobil") of 190 retail gasoline stations, together with the rights to (i) supply Mobil-branded fuel to those stations as well as an additional 31 existing locations in Massachusetts, New Hampshire and Rhode Island, and (ii) expand supply opportunities for Mobil-branded and Exxon-branded fuel in certain other New England states. This acquisition expanded our wholesale supply business and added vertical integration to our transportation fuel business in New

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England. On March 1, 2012, we acquired Alliance Energy LLC ("Alliance"), a gasoline distributor and operator of gasoline stations and convenience stores. As of the date of the acquisition, Alliance's portfolio included approximately 540 gasoline stations in the Northeast, of which it owned or held under long-term lease approximately 250 stations and had supply contracts for the remaining stations. The Alliance acquisition expanded our geographic footprint for gasoline stations to include Connecticut, New Jersey, New York, Pennsylvania, Maine and Vermont. Alliance is a top-tier distributor of multiple brands, including Exxon, Mobil, Shell, Sunoco, CITGO and Gulf. Prior to the closing of the acquisition, Alliance was wholly owned by AE Holdings Corp. ("AE Holdings") which, on March 1, 2012, was 95% owned by members of the Slifka family.

        On April 26, 2012, we entered into an agreement with Getty Realty Corp. ("Getty Realty") to supply and provide management services to more than 200 of its gasoline stations in New York and New Jersey. On November 19, 2012, we signed a long-term lease agreement with Getty Realty for approximately 90 of those 200 sites, which enables us to supply gasoline to and operate gasoline stations, primarily in the New York City boroughs of Queens, Manhattan and the Bronx as well as in Long Island and Westchester County. As of December 31, 2013, the supply and management agreement with respect to the remaining sites expired in accordance with the terms of the agreement.

    Commercial

        This segment includes sales and deliveries to end user customers in the public sector and to large commercial and industrial end users of unbranded gasoline, home heating oil, diesel, kerosene, residual oil, renewable fuels and natural gas. 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 barge or from a terminal dock to ships through our bunkering activity.

Seasonality

        Due to the nature of our business and our reliance, in part, on consumer travel and spending patterns, we may experience more demand for gasoline and gasoline blendstocks during the late spring and summer months than during the fall and winter. Travel and recreational activities are typically higher in these months in the geographic areas in which we operate, increasing the demand for gasoline and gasoline blendstocks that we distribute. Therefore, our volumes in gasoline and gasoline blendstocks are typically higher in the second and third quarters of the calendar year. 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, heating oil and residual oil sales are generally higher during the first and fourth quarters of the calendar year. These factors may result in significant fluctuations in our quarterly operating results. Portions of our heating oil and residual oil are sold on a forward fixed price basis. In 2013, our volumes in transportation fuels and crude oil exceeded our heating oil volumes.

Product Sales

    General

        We sell our refined petroleum products, renewable fuels, crude oil, natural gas and propane in three reporting segments: Wholesale, Gasoline Distribution and Station Operations and Commercial. The majority of the petroleum products we sell can be grouped into four categories: gasoline (including gasoline blendstocks such as ethanol and naphtha), distillates, residual oil and crude oil.

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        The following table presents our product sales and logistics revenue as a percentage of total sales for the years ended December 31:

 
  2013   2012   2011  

Gasoline sales: gasoline and gasoline blendstocks such as ethanol and naphtha

    58 %   68 %   68 %

Crude oil sales and logistics revenue

    18 %   7 %   *  

Distillates (home heating oil, diesel and kerosene), residual oil, natural gas and propane sales

    24 %   25 %   32 %
               

Total

    100 %   100 %   100 %
               
               

*
Less than 1/2%

        We had two significant customers, ExxonMobil and Phillips 66 who accounted for approximately 15% and 12%, respectively, of our total sales for the year ended December 31, 2013.

        We had one customer, ExxonMobil, who accounted for approximately 16% and 19% of our total sales for the years ended December 31, 2012 and 2011, respectively.

        Gasoline.    We sell all grades of branded and unbranded gasoline, and we sell gasoline blendstocks, such as ethanol that comply with seasonal and geographical requirements in the areas in which we market.

        Crude Oil.    We engage in the purchasing, selling and logistics of transporting domestic and Canadian crude oil and other products via rail and barge, establishing a "virtual pipeline" from the mid-continent region of the United States and Canada to the East and West Coasts for distribution to refiners and other customers.

        Distillates.    Distillates are divided into home heating oil, diesel and kerosene. In 2013, sales of home heating oil, diesel and kerosene accounted for approximately 57%, 41% and 2%, respectively, of our total volume of distillates sold.

        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 2013, approximately 10% 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®.

        Residual Oil.    We are one of the primary residual oil and bunker marketers in the Northeast. We specially blend product for users in accordance with their individual power specifications and for marine transport.

        Natural Gas.    We supply natural gas to industrial and commercial customers.

        Propane.    We sell propane to home heating oil retailers and wholesale distributors from our rail-fed propane storage and distribution facility near our existing terminal in Albany, New York.

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    Wholesale

        In the Wholesale reporting segment, we sell unbranded gasoline (including gasoline blendstocks such as ethanol and naphtha) and diesel to unbranded gasoline customers and other resellers of transportation fuels. We sell home heating oil, diesel, kerosene, residual oil and propane to home heating oil retailers and wholesale distributors. We also sell and transport crude oil to refiners. In 2013, this segment accounted for approximately 79% of our total volume sold. Generally, customers use their own vehicles or contract carriers to take delivery of the gasoline and distillate products at bulk terminals and inland storage facilities that we own or control or with which we have throughput or exchange arrangements. Please read "—Storage." Crude oil is aggregated by truck or pipeline in the mid-continent, transported on land by train and shipped to refineries on the East Coast and West Coast in barges. Additionally, ethanol is shipped primarily by rail and by barge.

        In 2013, we sold unbranded gasoline and diesel, including Diesel One®, to approximately 915 wholesalers and retail gasoline station operators.

        In 2013, we sold home heating oil, including Heating Oil Plus™, to approximately 900 wholesale distributors and retailers. We have a fixed price sales program that we market primarily to wholesale distributors and retailers which uses the New York Mercantile Exchange ("NYMEX") heating oil contract as the pricing benchmark and as the vehicle to manage the commodity risk. Please read "—Commodity Risk Management." In 2013, approximately 30% 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 2013, we moved a total of 493 trains of crude oil and ethanol through our Albany, New York facility (approximately 95,000 barrels per day).

        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.

    Gasoline Distribution and Station Operations

        In the Gasoline Distribution and Station Operations reporting segment, we sell branded and unbranded gasoline to gasoline stations and other sub-jobbers. This segment also includes gasoline, convenience store, car wash and other ancillary sales at our directly operated stores, as well as rental income from dealer leased or commission agent leased gasoline stations. As of December 31, 2013, we had a portfolio of approximately 900 owned, leased and/or supplied gasoline stations primarily in the Northeast. In 2013, this segment accounted for approximately 15% of our total volume sold.

        Financial information with respect to the Gasoline Distribution and Station Operations 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.

    Commercial

        Our Commercial segment includes sales and deliveries to end user customers in the public sector and to large commercial and industrial end users of unbranded gasoline, home heating oil, diesel, kerosene, residual oil, renewable fuels and natural gas. In the case of commercial and industrial end user customers, we sell products primarily either through a competitive bidding process or through contracts of various terms. Our Commercial segment also includes sales of custom blended fuels delivered by barges or from a terminal dock to ships through bunkering activity. In 2013, this segment accounted for approximately 6% of our total volume sold.

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        Our Commercial segment end user customers include 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. In the 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, 2013, we had contracts as a result of this public bidding process with the U.S. government and the states of Massachusetts, New Hampshire, New York 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 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 oil 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.

Supply

        Our products come from some of the major energy companies in the world as well as North American crude oil producers. Products can be sourced from the United States, Canada, South America, Europe, Russia and occasionally from Asia. Most of our products are delivered by water, pipeline, rail or truck. During 2013, we purchased an average of approximately 454,000 barrels per day of refined petroleum products, renewable fuels, crude oil and propane from over 180 suppliers. In 2013, our top ten suppliers accounted for approximately 52% 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

        When we take title to the 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, renewable fuels, crude oil and propane. We endeavor to minimize commodity risk in connection with our daily operations 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 market prices, fixed prices or indexed prices. While we use these transactions to 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, for example, associated with inclement weather conditions. In connection with managing these positions, maintaining a constant presence in the marketplace, and managing the futures market outlook for future anticipated inventories, which are necessary for our business, we engage in a

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controlled trading program for up to an aggregate of 250,000 barrels of these products at any point in time. 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, as well as inherent basis risk, exposure to fluctuations in market conditions remains.

        In addition, because a portion of our crude oil business is conducted in Canadian dollars ("CAD"), we use foreign currency derivatives to minimize the risks of unfavorable exchange rates. These instruments include foreign currency exchange contracts and forwards. In conjunction with entering into the commodity derivative, we enter into a foreign currency derivative to hedge the resulting foreign currency risk. These foreign currency derivatives are generally short-term in nature and not designated for hedge accounting.

        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 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 utilize futures contracts and other derivative instruments to minimize or hedge the impact of commodity price changes on our inventories and forward fixed price commitments. Any hedge ineffectiveness is reflected in our results of operations. We generally utilize regulated exchanges, including the NYMEX, the Chicago Mercantile Exchange ("CME") and the IntercontinentalExchange ("ICE"), which are regulated exchanges for the commodities that each trades, thereby reducing potential delivery and supply risks. Generally, our practice is to close all exchange positions rather than make or receive physical deliveries. We may also enter into derivative agreements which may not have a correlated exchange contract 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 eliminate commodity risk or detect and prevent all violations of such trading processes and procedures, particularly if deception or other intentional misconduct is involved.

        In our Wholesale segment, we obtain Renewable Identification Numbers ("RINs") in connection with our purchase of ethanol either to be used for bulk trading purposes or for blending with gasoline through our terminal system. A RIN is a renewable identification number associated with government-mandated renewable fuel standards. To evidence that the required volume of renewable fuel is blended with gasoline, obligated parties must retire sufficient RINs to cover their Renewable Volume Obligation ("RVO"). Our EPA obligations relative to renewable fuel reporting are largely limited to the foreign gasoline that we may choose to import. As a wholesaler of transportation fuels through its terminals, we separate RINs from renewable fuel through blending with gasoline and can use those separated RINs to settle our RVO. While the annual compliance period for a RVO is a calendar year, the settlement of the RVO can occur upon certain deferral elections more than one year after the close of

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the compliance period. Operating results are sensitive to the timing associated with our RINs position relative to our RVO at a point in time, and we may recognize a shortfall in RINs at the end of each reporting period. To the extent that we do not have a sufficient number of RINs to satisfy our obligation as of the balance sheet date, we charge cost of sales for such deficiency based on the market price of RINs as of the balance sheet date, and record a liability representing our obligation to purchase RINs.

        For more information about our policies and procedures to minimize our exposure to market risk, including commodity market risk, see Item 7, "Management's Discussion and Analysis and Results of Operations—Quantitative and Qualitative Disclosures About Market Risk."

Storage

        Bulk terminals and inland storage facilities play a key role in the distribution of product to our customers. As of December 31, 2013, we owned, leased or maintained dedicated storage facilities at 26 petroleum product bulk terminals, each with the capacity of more than 50,000 barrels, including 22 located throughout the Northeast that collectively have approximately 10.2 million barrels of storage capacity.

        We also have storage capacity at our Albany, New York, Clatskanie, Oregon and North Dakota terminals to store crude oil, at an Albany, New York terminal to store propane and at select locations to store renewable fuels. In addition, in Columbus, North Dakota we constructed a 100,000 barrel tank and a truck offloading facility in 2012 and a 170,000 barrel tank in 2013 as part of the development of a hub for the gathering, storage, rail transloading, transportation and marketing of crude oil and other products. In Beulah, North Dakota, through Basin Transload, we constructed two 140,000 barrel tanks and a truck offloading facility in 2013 to further develop that location as a hub for the gathering, storage, rail transloading, transportation and marketing of crude oil and other products.

        We also have throughput and exchange agreements at numerous bulk terminals and inland storage facilities. In addition, we have storage agreements at several of our terminals granting storage rights to third parties for which we receive a fee.

        The bulk terminals and inland storage facilities from which we distribute product are supplied by ship, barge, truck, pipeline and/or rail. The inland storage facilities, which we use primarily 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 and/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.

        We have exchange agreements with customers and suppliers. 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 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

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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

        In each of our operating segments, we encounter varying degrees of competition based on product and geographic locations and available logistics. Our competitors include terminal companies, major integrated oil companies and their marketing affiliates, wholesalers, producers and independent marketers of varying sizes, financial resources and experience. In our 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 are one of the primary residual oil marketers in the Northeast. We compete with other transloaders in our logistics activities including, in part, storage and transportation of crude oil, and the movement of product by alternative means (e.g., pipelines). We also compete with natural gas suppliers and marketers in our home heating oil, residual oil and propane 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 retail gasoline stations compete with unbranded and branded retail gas stations as well as supermarket and warehouse stores that sell gasoline.

Environmental

    General

        Our business of supplying refined petroleum products, renewable fuels, crude oil and propane 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 gasoline stations and must comply with environmental laws at the federal, state and local levels, which increases the cost of operating terminals and gasoline stations and our business generally. In addition, these laws are frequently modified or revised to impose new obligations.

        Our operations also utilize a number of petroleum storage facilities and distribution facilities, including rail transloading facilities and gasoline stations that we do not own or operate, but at which refined petroleum products, renewable fuels, crude oil and propane 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.

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        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, 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.

        Environmental operating permits are, or may be, required for our operations under applicable environmental laws and regulations. These operating permits are subject to modification, renewal and revocation. We regularly monitor and review our operations, procedures and policies for compliance with permits, laws and regulations. Despite these compliance efforts, risk of noncompliance or permit interpretation is inherent in the operation of our businesses, as it is with other companies engaged in similar businesses.

        The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment over time. 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 or have a material adverse effect on our financial position, results of operations or cash available for distribution to our unitholders.

    Hazardous Material Releases and Waste Handling

        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.

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        We currently own, lease or utilize storage or distribution facilities and gasoline 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.

        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 Storage Tanks

        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 at our terminals, we are required to file oil spill response plans with either the United States Coast Guard (for marine facilities) or the EPA. Many of the 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. We follow the American Petroleum Institute's inspection, maintenance and repair standard applicable to our above ground storage tanks.

        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.

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    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 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.

    Water Discharges

        The federal Clean Water Act imposes restrictions regarding the discharge of pollutants, including oil and refined petroleum products, renewable fuels and crude oil, 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.

    Air Emissions

        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 and renewable fuels 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.

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    Climate Change

        Federal climate change legislation in the U.S. appears unlikely in the near-term. As a result, domestic efforts to curb GHG emissions continue be led by the EPA GHG regulations and the efforts of states. To the extent that our operations are subject to the EPA's GHG regulations, we may face increased capital and operating costs associated with new or expanded facilities. Significant expansions of our existing facilities or construction of new facilities may be subject to the Clean Air Act's (the "CAA") Prevention of Significant Deterioration requirements under the EPA's GHG "Tailoring Rule." Some of our facilities are also subject to the EPA's Mandatory Reporting of Greenhouse Gases rule, and any further regulation may increase our operational costs.

        Under a consent decree with states and environmental groups, the EPA is due to propose new source performance standards for GHG emissions from refineries. These standards could significantly increase the costs of constructing or adding capacity to refineries and may ultimately increase the costs or decrease the supply of refined products. Either of these events could have an adverse effect on our business. Currently, however, it is not possible to estimate the likely financial impact of potential future regulation on any of our sites.

        Finally, it should be noted that some scientists have concluded that increasing concentrations of GHG in the earth's atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events. If any of those effects were to occur, they could have an adverse effect on our assets and operations.

        Under Subpart MM of the Mandatory Greenhouse Gas Reporting Rule ("MRR"), 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. We currently report under Subpart MM because of the volume of petroleum products we typically import. Compliance with the MRR does not substantially impact our operations. However, any change in regulations based on GHG emissions reported in compliance with MRR may limit our ability to import petroleum products or increase our costs to import such products.

    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.

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    Ethanol Market

        The market for ethanol is dependent on several economic incentives and regulatory mandates for blending ethanol into gasoline, including the availability of federal tax incentives, ethanol use mandates and oxygenate blending requirements. For instance, the Renewable Fuels Standard ("RFS") requires that a certain amount of renewable fuels, such as ethanol, be utilized in transportation fuels, including gasoline, in the United States each year. Additionally, the EPA imposes oxygenate blending requirements for reformulated gasoline that are best met with ethanol blending. Gasoline marketers may also choose to discretionally blend ethanol into conventional gasoline for economic reasons. The market for ethanol also has been affected by the Volumetric Ethanol Excise Tax Credit ("blender's credit"), which provided a volumetric tax credit of 4.5 cents per gallon of gasoline that contains at least 10% ethanol. The blender's credit expired on December 31, 2011. A change or waiver of the RFS mandate or the reformulated gasoline oxygenate blending requirements could adversely affect the availability and pricing of ethanol. Any change in the RFS mandate could also result in reduced discretionary blending of ethanol into conventional gasoline. Discretionary blending is when gasoline blenders use ethanol to reduce the cost of blended gasoline.

        In October 2010 and January 2011, the EPA granted two partial waivers that taken together 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 2001 and newer. E15 is not widely available in the U.S. and requires gasoline stations install "blender pumps" in order to sell E15 along with more conventional fuels such as E10 or E0. The USDA is providing financial assistance to help implement more "blender pumps" in the U.S. in order to increase the availability of E15 and to help offset the cost of introducing mid-level ethanol blends into the U.S. retail gasoline market. However, blender pumps cost approximately $20,000 each, so it may take time before they become widely available in the retail gasoline market. Additionally, according to EPA estimates, E85 flex-fuel vehicles make up only a small percentage of vehicles on the nation's roads and, as of January 2014, there were approximately 3,300 E85 stations in the U.S.

    Environmental Insurance

        We maintain insurance which may cover, in whole or in part, certain costs relating to the clean up of releases of the products we sell, including shipments by rail. We maintain insurance policies with insurers in amounts and with coverage and deductibles as we believe 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

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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.

Hazardous Materials Transportation

        Our operations include the preparation and shipment of some hazardous materials by truck, rail and marine vessel. We are subject to regulations promulgated under the Hazardous Materials Transportation Act (and subsequent amendments) and administered by the U.S. Department of Transportation under the Federal Highway Administration, the Federal Railroad Administration, the United States Coast Guard and the Pipeline and Hazardous Materials Safety Administration.

        We conduct loading and unloading of refined petroleum products, renewable fuels, crude oil and propane to and from cargo transports, including tanker trucks, railcars and marine vessels. In large part, the cargo transports are owned and operated by third parties. However, we lease a fleet of railcars associated with the shipment of refined petroleum products, renewable fuels and crude oil, and we own and operate a very limited number of trucks for the transportation of refined petroleum products. We conduct ongoing training programs to help ensure that our operations are in compliance with applicable regulations.

        Several recent derailments of freight trains including the tragic events in July 2013 in Lac Mégantic and the more recent events in Casselton, North Dakota, have lead federal and state regulators to examine whether the hazardous nature of crude oil from the Bakken Shale is being assessed properly prior to its shipment. In particular, there are concerns that the testing and ensuing designations of the crude oil on the shipping documentation do not in all cases accurately capture the flammability of the Bakken crude oil. On January 2, 2014, the Pipeline and Hazardous Materials Safety Administration ("PHMSA") released a Safety Alert alerting regulators, emergency responders, transporters and shippers that crude oil from the Bakken Shale may have flammability characteristics that are different from other forms of crude oil and that it was vital that all shipments of crude oil be tested and properly characterized on all shipping documentation. The Safety Alert also notified the regulated community that PHMSA and the Federal Railroad Administration have launched "Operation Classification," which is an enforcement initiative that involves unannounced inspections on crude oil shipments to test the contents of the shipments in order to ensure that they are properly characterized. While we cannot predict what the outcome of these safety efforts will be, any such requirements will apply to the industry generally.

        In addition, these events have also spurred efforts to improve the safety of tank cars that are used in transporting crude oil by rail. Since 2011, all new railroad tank cars that have been built to transport crude oil or other petroleum type fluids (e.g., ethanol) have been built to more stringent safety standards. On September 6, 2013, PHMSA issued an Advanced Notice of Proposed Rulemaking seeking comment on whether to impose additional requirements that would enhance the standards for tank cars used to transport hazardous materials such as crude oil from the Bakken Shale. This comment period closed in early December 2013. Were PHMSA to require safety improvements or updates to existing tank cars, that could drive up the cost of transport and lead to shortages in availability of tank cars. We cannot assure that costs incurred to comply with standards and regulations emerging from PHMSA's rulemaking process will not be material to our business, financial condition or results of operations. Any such requirements would apply to the industry as a whole.

        Efforts are likewise underway in Canada to assess and address risks from the transport of crude oil by rail. Shortly after the Lac Mégantic tragedy, Transport Canada issued a series of emergency directives aimed at certain practices that were identified immediately after the accident. Likewise, Transport Canada is assessing the compensation and liability scheme for shipments by rail so that

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sufficient funds are available to compensate victims and respond to the incident without making taxpayers fund any aspect of those efforts. More recently, in January 2104, the Canadian Transportation Safety Board made several recommendations to Transport Canada regarding tank car safety, routing of freight trains and the capabilities of emergency responders. While we cannot say how Canadian authorities will proceed regarding these recommendations, it seems likely that more stringent regulation of crude by rail shipments will ensue.

        We believe we are in substantial compliance with applicable hazardous materials transportation requirements related to our operations. We do not believe that compliance with federal, state or local hazardous materials transportation 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.

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, 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.

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, including certain sites within our Gasoline Distribution and Station Operations segment, may be subject to encumbrances, including repurchase rights and use, operating and environmental covenants and restrictions. 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 our trademarks. In addition, we have trademarks for our premium fuels and additives, Diesel One®, Heating Oil Plus™ and SubZero® and a pending trademark for our Alltown convenience store locations.

Facilities

        We lease office space for our principal executive office in Waltham, Massachusetts. The lease expires on July 31, 2026.

Employees

        To carry out our operations, our general partner and certain of our operating subsidiaries employed 943 full-time employees as of December 31, 2013. We believe we have good relations with our employees.

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        There are three collective bargaining agreements governing the employment of certain of the employees assigned to our terminal in Chelsea, Massachusetts. The drivers and terminal operators are employed under collective bargaining agreements that expired in March 2014, and the dispatchers are employed under a collective bargaining agreement that expires in 2015. Certain of Global Petroleum Corp.'s employees at the Revere, Massachusetts facility are employed under a collective bargaining agreement that expired in March 2014. We are negotiating new collective bargaining agreements with respect to the collective bargaining agreements that expired in March 2014. We do not believe the result of these negotiations will have a material adverse effect on our operations. Certain of the employees assigned to our terminals in Albany, Newburgh, Glenwood Landing and Inwood, New York are employed under collective bargaining agreements that expired in 2013 (with respect to Albany and one of our terminals in Newburgh), and that expire in 2014 (with respect to Glenwood Landing and Inwood) and 2016 (with respect to our other terminals in Newburgh). We have negotiated the terms of a new collective bargaining agreement with respect to the collective bargaining agreement that expired in 2013.

        Certain of the employees assigned to our terminal in Oyster Bay (Commander), New York are employed under a collective bargaining agreement that expired in February 2014. We have negotiated the terms of a new collective bargaining agreement with respect to the collective bargaining agreement that expired in February 2014.

        Certain of the employees assigned to the Cascade Kelly facility in Clatskanie, Oregon are employed under a collective bargaining agreement that expires in 2014.

        We have a shared services agreement with Global Petroleum Corp. The services provided among these entities by any employees shared pursuant to these agreements do 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." In connection with our acquisition of Alliance on March 1, 2012, we terminated our shared services agreement with Alliance effective as of March 9, 2012.

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, renewable fuels, crude oil, natural gas and propane;

    demand for refined petroleum products, renewable fuels, crude oil, natural gas and propane in the markets we serve;

    absolute price levels, as well as the volatility of prices, of refined petroleum products, renewable fuels, RINs, crude oil, natural gas and propane in both the spot and futures markets;

    supply, extreme weather and logistics disruptions;

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

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    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 and the indentures governing our senior notes, including financial covenants, 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.

The amount of cash we have available for distribution to unitholders depends 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 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.

We may not be able to fully implement or capitalize upon planned growth projects.

        We have a number of organic growth projects that require the expenditure of significant amounts of capital in the aggregate. Many of these projects involve numerous regulatory, environmental, commercial and legal uncertainties that will be beyond our control. As these projects are undertaken, required approvals, permits and licenses may not be obtained, may be delayed or may be obtained with conditions that materially alter the expected return associated with the underlying projects. Moreover, revenues associated with these organic growth projects will not increase immediately upon the expenditures of funds with respect to a particular project and these projects may be completed behind schedule or in excess of budgeted cost. We may pursue projects in anticipation of market demand that dissipates or market growth that never materializes. As a result of these uncertainties, the anticipated benefits associated with our capital projects may not be achieved.

We commit substantial resources to pursuing acquisitions, although there is no certainty that we will successfully complete any acquisitions or receive the economic results we anticipate from completed acquisitions.

        We are continuously engaged in discussions with potential sellers and lessors of existing (or suitable for development) terminalling, storage, logistics and/or marketing assets, including gasoline stations, and related businesses. Our growth largely depends on our ability to make accretive acquisitions and/or accretive development projects. We may be unable to execute such accretive transactions for a number of reasons, including, but not limited to, the following: (1) we are unable to identify attractive transaction candidates or negotiate acceptable terms; (2) we are unable to obtain financing for such transactions on economically acceptable terms; or (3) we are outbid by competitors. In addition, we may consummate transactions 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

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growth and ability to increase distributions could be limited. We can give no assurance that our efforts will be successful or that any such transaction will be completed on terms that are favorable to us.

        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;

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

    a significant increase in our indebtedness and working capital requirements;

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

    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;

    mistaken assumptions about the overall costs of equity or debt;

    the assumption of substantial unknown or 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;

    limitations on rights to indemnity from the seller;

    customer or key employee loss from the acquired businesses;

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

    diversion of our management's and employees' 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 increase distributions may be reduced.

Our gasoline and gasoline blendstocks financial results are seasonal and generally lower in the first and fourth quarters of the calendar year.

        Our results of operations in gasoline and gasoline blendstocks are typically lower in the first and fourth quarters of the calendar year. Due to the nature of our business and our reliance, in part, on consumer travel and spending patterns, we may experience more demand for gasoline and gasoline blendstocks during the late spring and summer months than during the fall and winter. Travel and recreational activities are typically higher in these months in the geographic areas in which we operate, increasing the demand for gasoline and gasoline blendstocks that we distribute. Therefore, our results of operations in gasoline and gasoline blendstocks are typically lower in the first and fourth quarters of the calendar year.

Our heating oil and residual oil financial results are seasonal and generally lower in the second and third 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 the winter months. Therefore, our results of operations in heating oil and residual oil for the first and fourth calendar quarters are generally better than for the second and third quarters.

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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 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.

A significant decrease in demand for refined petroleum products, renewable fuels, crude oil and propane in the areas we serve would reduce our ability to make distributions to our unitholders.

        A significant decrease in demand for refined petroleum products, renewable fuels crude oil and propane 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, renewable fuels crude oil include and propane:

    a recession or other adverse economic conditions or due to high prices caused by an increase in the market price of refined petroleum products, renewable fuels and propane or higher fuel taxes or other governmental or regulatory actions that increase, directly or indirectly, the cost of gasoline or other refined petroleum products, renewable fuels crude oil and propane;

    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 business is influenced by the overall forward market for refined petroleum products, renewable fuels and crude oil, and increases and/or decreases in the prices of these products may adversely impact our financial condition, results of operations and cash available for distribution to our unitholders and the amount of borrowing available for working capital under our credit agreement.

        Results from our purchasing, storing, terminalling, transporting and selling operations are influenced by prices for refined petroleum products, renewable fuels and crude oil, pricing volatility and the market for such products. Prices in the overall forward market for these products may affect our financial condition, results of operations and cash available for distribution to our unitholders. Our margins can be significantly impacted by the forward product pricing curve, often referred to as the futures market. We typically hedge our exposure to petroleum product and renewable fuel price moves with futures contracts and, to a lesser extent, swaps. In markets where futures prices are higher than current prices, referred to as contango, 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 markets where futures prices are lower than current prices, referred to as backwardation, inventories can depreciate in value and hedging costs are more expensive. For this reason, in these backward markets, we attempt to reduce our inventories in order to minimize these effects.

        When prices for the products we sell 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

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on to our customers, resulting in lower margins for us which could adversely affect our results of operations. Higher prices for the products we sell 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.

        When prices for the products we sell 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 the products we sell at the then lower market price from a competitor. A significant decrease in the price for crude oil could adversely affect the economics of the domestic crude oil production for the product which, in turn, could have an adverse effect on our crude oil logistics activities and sales.

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

        As of December 31, 2013, our total debt, including amounts outstanding under our credit agreement, senior notes and bank line of credit, was approximately $913.7 million. We have the ability to incur debt, including the capacity to borrow up to $1.625 billion under our credit agreement, 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 or eliminating 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.

A significant increase in interest rates could adversely affect our ability to service our indebtedness.

        The interest rates on our credit agreement are variable; therefore, we have exposure to movements in interest rates. A significant increase in interest rates could adversely affect our ability to service our indebtedness. The increased cost could make the financing of our business activities more expensive. These added expenses could have an adverse effect on our financial condition, results of operations and cash available for distribution to our unitholders.

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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.

        In the 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 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 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 and the indentures governing our senior notes contain operating and financial restrictions and covenants that may restrict our business and financing activities.

        The operating and financial restrictions and covenants in our credit agreement and the indentures governing our senior notes 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; or

    modify borrowing base components and advance rates.

        In addition, the indentures governing our senior notes limit our ability to, among other things:

    incur additional indebtedness;

    make distributions to equity owners;

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    make certain investments;

    restrict distributions by our subsidiaries;

    create liens;

    enter into sale-leaseback transactions;

    sell assets; or

    merge with other entities.

        Our ability to comply with the covenants and restrictions contained in our credit agreement and the indentures 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 or the indentures, 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.

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

        Our credit agreement and the indentures limit our ability to pay distributions upon the occurrence of certain events. For example, each of our credit agreement and the indentures limits our ability to pay distributions upon the occurrence of the following events, among others:

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

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

    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 and the indentures, 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" and Note 8 of Notes to Consolidated Financial Statements.

The enactment of derivatives legislation could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.

        On July 21, 2010, new comprehensive financial reform legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Act"), was enacted that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The Act requires the Commodities Futures Trading Commission ("CFTC"), the SEC and

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other regulators to promulgate rules and regulations implementing the new legislation. Although the CFTC has finalized certain regulations, others remain to be finalized or implemented and it is not possible at this time to predict when this will be accomplished.

        In October 2010, pursuant to its rulemaking under the Act, the CFTC issued rules to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. The initial position limits rule was vacated by the United States District Court for the District of Columbia in September of 2012. However, in November 2013, the CFTC proposed new rules that would place limits on positions in certain core futures and equivalent swaps contracts for, or linked to, certain physical commodities, subject to exceptions for certain bona fide hedging transactions. As these new position limit rules are not yet final, the impact of those provisions on us is uncertain at this time.

        The CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing and exchange trading. To the extent we engage in such transactions or transactions that become subject to such rules in the future, we will be required to comply or take steps to qualify for an exemption to such requirements. Although we expect to qualify for the end-user exception to the mandatory clearing requirements for swaps entered to hedge our commercial risks, the application of the mandatory clearing and trade execution requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. In addition, the Act requires that regulators establish margin rules for uncleared swaps. Rules that require end-users to post initial or variation margin could impact our liquidity and reduce cash available for capital expenditures, therefore reducing our ability to execute hedges to reduce risk and protect cash flows. The proposed margin rules for uncleared swaps are not yet final and their impact on us is not yet clear.

        The Act also may 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 full impact of the Act and related regulatory requirements upon our business will not be known until the regulations are implemented and the market for derivative contracts has adjusted. The Act and any new regulations could significantly increase the cost of derivative contracts (including from swap recordkeeping and reporting requirements and through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of 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. If we reduce our use of derivatives as a result of the Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Any of these consequences could have material adverse effect on our financial condition, results of operations and cash available for distributions to our unitholders.

        In addition, the European Union and other non-U.S. jurisdictions are implementing regulations with respect to the derivatives market. To the extent we transact with counterparties in foreign jurisdictions, we may become subject to such regulations. At this time, the impact of such regulations is not clear.

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

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inventory, we may be unhedged for the amount of the overestimate or underestimate. Also, significant increases in the costs of the products we sell 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.

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 petroleum product and renewable fuel prices or disruptions in the credit markets or for any other reason. Any of these events could adversely affect our financial condition, results of operations and cash available for distribution to our unitholders.

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, renewable fuels crude oil and propane 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 may purchase refined petroleum products, renewable fuels crude oil and propane 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

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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.

Historical prices for certain products we sell have been volatile and significant changes in such prices in the future may adversely affect our financial condition, results of operations and cash available for distribution to our unitholders.

        Historical prices for certain products we sell were volatile. General political conditions, acts of war or terrorism and instability in oil producing regions, particularly in the Middle East, Russia, Africa and South America, could significantly impact crude oil supplies and wholesale motor fuel costs. Significant increases and volatility in wholesale gasoline costs could result in significant increases in the retail price of motor fuel products and in lower margins per gallon. Increases in the retail price of motor fuel products could impact consumer demand for motor fuel. This volatility makes it extremely difficult to predict the impact future wholesale cost fluctuations will have on our operating results and financial condition. Dramatic increases in crude oil prices squeeze fuel margins because fuel costs typically increase faster than can pass along such increases to customers. Higher fuel prices trigger higher credit card expenses, because credit card fees are calculated as a percentage of the transaction amount, not as a percentage of gallons sold. A significant change in any of these factors could materially impact our customer's needs, motor fuel gallon volumes, gross profit and overall customer traffic, which in turn could have a material adverse effect on our financial condition, results of operations and cash available for distribution to our unitholders.

New technologies and alternative fuel sources as well as higher prices 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. In addition, higher prices 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.

Energy efficiency, higher prices, 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. During periods of increasing home heating oil prices relative to the price of 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, higher prices and 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.

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

        We believe that the success of our acquisitions of retail gasoline stations and supply rights from ExxonMobil in 2010 and our acquisition of Alliance in 2012 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 acquisition to be less profitable.

We depend upon marine, pipeline, rail and truck transportation services for a substantial portion of our logistics business in transporting the products we sell. A disruption in these transportation services could have an adverse effect on our financial condition, results of operations and cash available for distribution to our unitholders.

        Hurricanes, flooding and other severe weather conditions could cause a disruption in the transportation services we depend on which could affect the flow of service. In addition, accidents, labor disputes between the railroads and their union employees and labor renegotiations, or a work stoppage at railroads, could also disrupt rail service. These events could result in service disruptions and increased cost which could also adversely affect our financial condition, results of operations and cash available for distribution to our unitholders. Other disruptions, such as those due to an act of terrorism or war, could also adversely affect our business.

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 EPA's regulations on the RFS program and oxygenate blending requirements. A reduction or waiver of the RFS mandate or oxygenate blending requirements could adversely affect the availability and pricing of ethanol, which in turn could adversely affect our future gasoline and ethanol sales. In addition, events including changes in blending requirements could affect the price of RINs which could impact the magnitude of the mark-to-market liability recorded for the deficiency, if any, in our RIN position relative to our RVO at a point in time.

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

        Where releases of refined petroleum products, renewable fuels, crude oil and propane 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 gasoline 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. Any such action could adversely affect our financial condition and results of operations. 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

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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, transporting, storage and logistics activities. Competition from other providers of refined petroleum products, renewable fuels, crude oil, natural gas and propane that are able to supply our customers with those products and services at a lower price and have capital resources many times greater than ours could reduce our ability to make distributions to our unitholders.

        We are subject to competition from distributors and suppliers of refined petroleum products, renewable fuels, crude oil, natural gas and propane that may be able to supply our customers with the same or comparable products and terminalling, transporting and storage services and logistics on a more competitive basis. We compete with terminal companies, major integrated oil companies and their marketing affiliates, wholesalers, producers and independent marketers of varying sizes, financial resources and experience. In our 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 compete with other transloaders in our logistics activities including, in part, storage and transportation of crude oil, and the movement of product by alternative means (e.g., pipelines). We also compete with natural gas suppliers and marketers in our home heating oil, residual oil and propane 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 retail gasoline stations compete with unbranded and branded retail gas stations as well as supermarket and warehouse stores that sell gasoline.

        Some of our competitors are substantially larger than us, have greater financial resources and control greater supplies of refined petroleum products, renewable fuels, crude oil, natural gas and propane than we do. 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, and 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.

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 17 bulk terminals. The agreements governing these arrangements are subject to expiration at various dates through 2019.

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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.

We may not be able to lease sites we own or sub-lease sites we lease with respect to the sale of gasoline on favorable terms and any such failure could adversely affect our financial condition, results of operations and cash available for distribution to our unitholders.

        We may lease certain sites to dealers where the rent expense is more than the lease payments. If we are unable to obtain tenants on favorable terms for sites we own or lease, the lease payments we receive may not be adequate to cover our rent expense for leased sites and may not be adequate to ensure that we meet our debt service requirements. We cannot provide any assurance that our gross margin from the sale of transportation fuels and related convenience store items at these sites will be adequate to offset unfavorable lease terms. The occurrence of these events could adversely affect 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 the estate of Alfred A. Slifka and Richard Slifka). As of December 31, 2013, this facility accounted for approximately 21% of our storage capacity. We store distillates and gasoline and gasoline blendstocks at this facility. The throughput agreement for this facility expires in 2015. 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 renegotiated or replaced periodically. 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, renewable fuels, crude oil, natural gas and propane 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.

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

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decreases in demand for refined petroleum products, renewable fuels, crude oil and propane, 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.

        We store gasoline renewable fuels, crude oil and propane in underground and above ground storage tanks. Our operations are also subject to significant hazards and risks inherent in storing gasoline. These hazards and risks include, but are not limited to, fires, explosions, spills, discharges and other releases, any of which could result in distribution difficulties and disruptions, environmental pollution, governmentally-imposed fines or clean-up obligations, personal injury or wrongful death claims and other damage to our properties and the properties of others.

        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 results of operations and financial condition.

        Our operations are subject to federal, state and local laws and regulations regulating operations, 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 over time. Our business may be adversely affected by increased costs and liabilities and interruption in the ability to operate 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.

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, renewable fuels crude oil and propane 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

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stringent federal, state and local environmental laws in 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, renewable fuels, crude oil and propane 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, renewable fuels crude oil and propane, 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.

        Additionally, the construction of new terminals or the expansion of an existing terminal involves numerous regulatory, environmental, political and legal uncertainties, most of which are not in our control. Delays, litigation, local concerns and difficulty in obtaining approvals for projects requiring federal, state or local permits could impact our ability to build, expand and operate strategic facilities and infrastructure, which could adversely impact growth and operational efficiency.

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 considered various proposals to reduce GHG emissions. Many states and regions have adopted GHG initiatives. Please read "Items 1. and 2. Business and Properties—Environmental—Air Emissions."

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        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. Future international, federal and state initiatives to control carbon dioxide emissions could result in increased 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.

Our business involves the buying, selling and shipping by rail of crude oils including from the Bakken Shale, which involves risks of derailment, accidents and liabilities associated with cleanup and damages, as well as potential regulatory changes that may adversely impact our business, financial condition or results of operations.

        Our operations involve the buying and selling of crude oil including from the Bakken Shale and shipping it by rail to various markets including on rail cars that we lease. In 2013, there were several different incidents involving the derailments of railroad cars carrying crude oil from the Bakken Shale including the tragedy in Lac Mégantic, Quebec, in Alabama and in North Dakota. Transportation safety regulators in the United States and Canada are concerned that crude oil from the Bakken Shale may be more flammable than crude oil from other producing regions and are investigating that issue and are also considering changes to existing regulations to address those possible risks. Any changes to the existing regulations may require us to make expenditures to comply that are material to our operations. Any derailment of crude oil from the Bakken Shale involving crude oil that we have purchased or are shipping may result in claims being brought against us that may involve significant liabilities. Although we believe that we are adequately insured, we cannot assure you that our policies will cover the entirety of any damages that may arise from such an event.

        Recent derailments in North America of trains transporting crude oil have caused various regulatory agencies and industry organizations, as well as federal, state and municipal governments, to focus attention on transportation by rail of flammable materials. For example, in September 2013, the PHMSA published an Advance Notice of Proposed Rulemaking seeking interested party comments on potential regulatory initiatives pertaining to the transportation of flammable materials by rail. We are unable to predict what regulatory changes may be made in this regard, if any, or the time period during which any such regulatory changes may become effective. Any final rule may materially impact the rail industry as a whole. We cannot assure that costs incurred to comply with any new standards and regulations, including any emerging from PHMSA's rulemaking process, will not be material to our business, financial condition or results of operations.

We are subject to federal, state and local laws and regulations that govern the product quality specifications of the refined petroleum products, renewable fuels and propane 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.

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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 and state 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 USTs 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 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, renewable fuels, crude oil and propane. 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.

        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.

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        Certain executive officers of our general partner perform services for certain of our affiliates pursuant to shared services agreements. 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 certain of our terminals 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 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 effectively. 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.

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 28, 2014, affiliates of our general partner, including directors and executive officers and their affiliates, owned 42.3% of our common units and the entire 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

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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.

    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."

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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 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 10, 2014, affiliates of our general partner, including directors and executive officers and their affiliates, owned 42.3% of our common units.

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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 28, 2014, we had 27,430,563 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 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. Pursuant to the Registration Rights Agreement, AE Holdings has registration rights with respect to units issued in connection with the Alliance acquisition.

        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

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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.

Cost reimbursements due to 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.

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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.

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

        Mr. Alfred A. Slifka, Mr. Richard Slifka and their affiliates (other than us) are subject to noncompetition provisions in the omnibus agreement and business opportunity agreement. In addition Mr. Eric Slifka's and Mr. Andrew Slifka's employment agreements contain noncompetition provisions. These agreements do not prohibit Messrs. Alfred A. Slifka, Richard Slifka, Eric Slifka and 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 and—Business Opportunity 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, which would subject us to entity level taxation, then our cash available for distribution to our 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 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 ours to be treated as a corporation for federal income tax purposes. Although we do not believe based upon our current operations that we are or will be 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.

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        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 and local income tax at varying rates. Distributions would generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains, losses, deductions or credits would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to our unitholders would be substantially reduced. Therefore, if we were treated as a corporation for federal income tax purposes, there would be a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our 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 and other forms of taxation. Imposition of any such taxes by individual states may substantially reduce the cash available for distribution to our unitholders and, therefore, 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 additional amounts of entity level taxation, the minimum quarterly distribution amount and the target distribution amounts may 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 differing interpretations, possibly applied 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 changes or differing interpretations at any time. For example, from time to time, members of Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships. One such legislative proposal would have eliminated the qualifying income exception to the treatment of all publicly traded partnerships as corporations, upon which we rely for our treatment as a partnership for U.S. federal income tax purposes. 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 any of these changes, or other proposals, will be re-introduced or 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 three subsidiaries that are treated as corporations for federal income tax purposes and subject to corporate-level income taxes.

        We conduct substantially all of our operations of our end-user business through three subsidiaries that are treated as corporations for federal income tax purposes. One of these corporations engages in the retail sale of gasoline and/or operate convenience stores with respect to certain of the stations we acquired from ExxonMobil and Alliance and collect rents on personal property leased to dealers and commissioned agents at other stations we acquired from ExxonMobil and Alliance. We may elect to

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conduct additional operations through these corporate subsidiaries in the future. These corporate subsidiaries are subject to corporate-level taxes, which reduce the cash available for distribution to us and, in turn, to unitholders. If the IRS were to successfully assert that these corporations have 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 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 subject to withholding taxes imposed at the highest tax rate applicable to such non-U.S. persons, and each non-U.S. person 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.

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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, and although the U.S. Treasury Department issued proposed Treasury Regulations allowing a similar monthly simplifying convention, such regulations are not final and do not specifically authorize the use of the proration method we have adopted. Accordingly, our counsel is unable to opine as to the validity of this method. If the IRS were to challenge our proration method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

A unitholder whose units are 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)

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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 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 would result in us filing two tax returns (and our unitholders receiving two Schedule K-1s) for one calendar year. However, pursuant to an IRS relief procedure, the IRS may allow, among other things, a constructively terminated partnership to provide a single Schedule K-1 for the calendar year in which a termination occurs. 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 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.

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, 2013, we conducted business in 30 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.

    General

        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 or results of operations. Except as

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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.

    Environmental

        In connection with the December 2012 acquisition of six New England gasoline stations from Mutual Oil Company, we assumed certain environmental liabilities, including certain ongoing remediation efforts. As a result, we recorded a total environmental liability of approximately $0.6 million which was recorded as a long-term liability at December 31, 2013.

        In connection with the March 2012 acquisition of Alliance, we assumed Alliance's environmental liabilities, including ongoing environmental remediation at certain of the retail stations owned by Alliance and future remediation activities required by applicable federal, state or local law or regulation. Remedial action plans are in place, as may be applicable with the state agencies regulating such ongoing remediation. Based on reports from environmental engineers, our estimated cost of the ongoing environmental remediation for which Alliance was responsible and future remediation activities required by applicable federal, state or local law or regulation is estimated to be approximately $16.1 million to be expended over an extended period of time. Certain environmental remediation obligations at the retail stations acquired by Alliance from ExxonMobil in 2011 are being funded by a third-party who assumed the liability in connection with the Alliance/ExxonMobil transaction in 2011 and, therefore, cost estimates for such obligations at these stations are not included in this estimate. As a result, we recorded, on an undiscounted basis, total environmental liabilities of approximately $16.1 million. At December 31, 2013, this liability had a remaining balance of approximately $13.9 million.

        In connection with the September 2010 acquisition of retail gasoline stations from ExxonMobil, we assumed certain environmental liabilities, including ongoing environmental remediation at and monitoring activities at certain of the acquired sites and future remediation activities 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. 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. As a result, we recorded, on an undiscounted basis, total environmental liabilities of approximately $30.0 million. At December 31, 2013, this liability had a remaining balance of approximately $24.7 million.

        In connection with the June 2010 acquisition of three refined petroleum products terminals in Newburgh, New York, 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, which was recorded as a long-term liability at December 31, 2013.

        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, on an undiscounted basis, total environmental liabilities of approximately $1.2 million. At December 31, 2013, this liability had a remaining balance of approximately $0.3 million.

        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, on an undiscounted basis,

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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. 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. The remedial action work has been implemented pursuant to the approved work plan, and the post-remediation stage of operation, monitoring and maintenance has commenced and is ongoing. As a result, we changed our estimate and reduced the environmental liability by $1.7 million during the second quarter ended June 30, 2011. At December 31, 2013, this liability had a remaining balance of approximately $47,000.

        For additional information regarding our environmental liabilities, see Note 9 of Notes to Consolidated Financial Statements included elsewhere in this report.

    Other

        On December 30, 2013, the Oregon Department of Environmental Quality ("ODEQ") unilaterally modified (the "Modification") an air emissions permit held by our subsidiary, Cascade Kelly Holdings LLC, which covers both the production of ethanol and transshipping of crude oil by our bio-refinery in Clatskanie, Oregon (the "Existing Permit"). This Modification proposed to limit the number of trains carrying crude oil that the bio-refinery can receive as part of our transloading operations. We submitted a request for a hearing contesting the Modification, which allows the Existing Permit to remain in effect pending such appeal. In addition, we received a Pre-Enforcement Notice ("PEN") letter dated January 10, 2014 from ODEQ claiming that we are in violation of the Existing Permit and informing us that ODEQ is considering a possible notice of violation and penalty assessment. In summary, the PEN asserts that we may have received, and be receiving, more crude oil than the Existing Permit allows. On March 27, 2014, ODEQ issued us a civil penalty assessment ("CPA") of $117,292. We believe that we have meritorious defenses to the Modification, the PEN and the CPA and will vigorously contest any actions that may be taken by ODEQ with respect to the foregoing.

        Separately, in August 2013, we submitted an application to ODEQ for a separate air emissions permit covering the transloading of crude oil by the bio-refinery (the "New Permit"). We are working through the customary permitting process with ODEQ. The draft of the New Permit is currently out for public notice and comment. We anticipate that the New Permit will be issued in the second quarter of 2014. We believe that the issuance of the New Permit will resolve ODEQ's concerns regarding the Existing Permit as noted above. It is possible, however, that the issuance of the New Permit may be delayed and that a significant delay may have a negative impact on our operations in Oregon.

        We received from the EPA, by letters dated November 2, 2011 and March 29, 2012, reporting requirements and testing orders (collectively, the "Requests for Information") for information under the Clean Air Act. The Requests for Information are part of an EPA investigation to determine whether we have violated sections of the Clean Air Act at certain of our terminal locations in New England with respect to residual oil and asphalt. We have submitted all required information requested under the Requests for Information. We do not believe that a material violation has occurred nor do we believe any adverse determination in connection with such investigation would have a material impact on our operations.

Item 4.    Mine Safety Disclosures

        Not applicable.

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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 20, 2014 was $35.78. At the close of business on March 24, 2014, based upon information received from our transfer agent and brokers and nominees, we had 10,255 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  

2013

                   

Fourth Quarter

  $ 37.50   $ 31.50   $ 0.6125  (b)

Third Quarter

    40.99     30.01     0.6000  

Second Quarter

    40.00     32.02     0.5875  

First Quarter

    38.45     25.33     0.5825  

2012

   
 
   
 
   
 
 

Fourth Quarter

  $ 27.91   $ 21.93   $ 0.5700  

Third Quarter

    26.40     22.22     0.5325  

Second Quarter

    23.84     20.01     0.5250  

First Quarter

    24.75     21.88     0.5000  

(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, 2014 to unitholders of record on February 5, 2014.

        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 earnings, 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. The indentures governing our outstanding senior notes also limit our ability to make distributions to our unitholders.

        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;

    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.

        We will make distributions of available cash from distributable cash flow for any quarter in the following manner: 99.17% to the common unitholders, pro rata, and 0.83% 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 distribution is distributed to the unitholders and the general partner based on the percentages as provided below.

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        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     99.17%     0.83%  

First Target Distribution

  $0.4625     99.17%     0.83%  

Second Target Distribution

  above $0.4625 up to $0.5375     86.17%     13.83%  

Third Target Distribution

  above $0.5375 up to $0.6625     76.17%     23.83%  

Thereafter

  above $0.6625     51.17%     48.83%  

        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 and Related Stockholder Matters—Equity Compensation Plan Table."

Recent Sales of Unregistered Securities

        None.

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, 2013:

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, 2013

                 

November 1-November 30, 2013

                 

December 1-December 31, 2013

    7,500     34.47         247,012  

(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 Long-Term Incentive Plan ("LTIP") and meeting the general partner's obligations under existing employment agreements and other employment related obligations of the general partner. Our general partner is currently authorized to acquire up to 742,427 of our common units in the aggregate to be acquired 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

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States ("GAAP"). We explain these measures and present reconciliations to their most directly comparable financial measures calculated in accordance with GAAP in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations—Key Performance Indicators."

 
  Year Ended December 31,  
 
  2013   2012   2011   2010   2009  
 
  (dollars in millions except per unit amounts)
 

Statement of Income Data:

                               

Sales

  $ 19,589.6   $ 17,626.0   $ 14,835.7   $ 7,801.5   $ 5,818.4  

Cost of sales

    19,183.8     17,292.5     14,626.1     7,634.8     5,668.6  
                       

Gross profit

    405.8     333.5     209.6     166.7     149.8  

Selling, general and administrative expenses

    115.5     95.7     73.9     63.1     60.0  

Operating expenses

    185.7     140.4     73.5     47.8     35.0  

Restructuring charges

            2.0          

Amortization expense

    19.2     7.0     4.8     3.5     3.0  
                       

Total operating costs and expenses

    320.4     243.1     154.2     120.4     100.0  
                       

Operating income

    85.4     90.3     55.4     52.3     51.8  

Interest expense

    (43.5 )   (42.0 )   (35.9 )   (25.3 )   (16.2 )
                       

Income before income tax expense

    41.9     48.3     19.4     27.0     35.6  

Income tax expense

    (0.9 )   (1.6 )           (1.5 )
                       

Net income

    41.0     46.7     19.4     27.0     34.1  

Net loss attributable to noncontrolling interest (1)

    1.6                  
                       

Net income attributable to Global Partners LP

    42.6     46.7     19.4     27.0     34.1  

Less: General partner's interest in net income

    (3.5 )   (1.2 )   (0.7 )   (0.6 )   (0.8 )
                       

Limited partners' interest in net income

  $ 39.1   $ 45.5   $ 18.7   $ 26.4   $ 33.3  
                       
                       

Basic net income per limited partner unit (2)

  $ 1.43   $ 1.73   $ 0.88   $ 1.61   $ 2.56  
                       
                       

Diluted net income per limited partner unit (2)

  $ 1.42   $ 1.71   $ 0.87   $ 1.59   $ 2.51  
                       
                       

Basic weighted average limited partner' units outstanding

    27.3     26.4     21.3     16.3     13.0  
                       
                       

Diluted weighted average limited partner' units outstanding

    27.6     26.6     21.5     16.6     13.3  
                       
                       

Cash Flow Data:

                               

Net cash provided by (used in)

                               

Operating activities

  $ 255.1   $ 232.4   $ (17.4 ) $ (87.2 ) $ (61.1 )

Investment activities

    (243.2 )   (226.5 )   (13.4 )   (263.0 )   (9.1 )

Financing activities

    (8.7 )   (4.3 )   32.7     351.9     69.9  

Other Financial Data:

                               

EBITDA (3)

  $ 157.4   $ 135.8   $ 85.7   $ 72.4   $ 66.7  

Distributable cash flow (4)

    105.2     80.8     46.7     46.0     45.4  

Capital expenditures—acquisitions (5)

    185.3     188.7         248.4      

Capital expenditures—maintenance and expansion (5)

    67.1     44.9     16.0     14.7     9.1  

Cash distributions per limited partner unit (6)

    2.34     2.06     2.00     1.96     1.95  

Operating Data:

                               

Normal heating degree days (7)

    5,630     5,661     5,630     5,630     5,630  

Actual heating degree days

    5,521     4,754     5,137     5,049     5,656  

Variance from normal heating degree days

    (2% )   (16% )   (9% )   (10% )   1%  

Variance from prior year actual degree days

    16%     (7% )   2%     (11% )   4%  

Total gallons sold (in millions)

    6,956     6,100     5,217     3,650     3,404  

Variance in volume sold from prior year

    14%     17%     43%     7%     (4% )

Balance Sheet Data (at period end):

                               

Cash and cash equivalents

  $ 9.2   $ 6.0   $ 4.3   $ 2.4   $ 0.6  

Property and equipment, net

    803.6     712.3     408.8     422.7     159.3  

Total assets

    2,427.9     2,329.8     1,876.6     1,672.3     1,052.7  

Total current liabilities

    972.6     1,045.2     778.8     751.7     567.6  

Long-term debt

    913.0     762.8     731.1     593.5     312.1  

Total debt

    913.7     846.5     793.9     786.7     533.8  

Total liabilities

    1,964.7     1,893.3     1,561.3     1,395.5     895.3  

Partners' equity

    463.2     436.5     315.3     276.8     157.4  

(1)
On February 1, 2013, we acquired a 60% membership interest in Basin Transload LLC (see Note 3 of Notes to Consolidated Financial Statements included elsewhere in this report). The net loss for 2013 is attributable to the noncontrolling interest which represents Basin Transload's 40% interest.

(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") 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 under "Results of Operations—Key Performance Indicators" in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations."

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(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 under "Results of Operations—Key Performance Indicators" 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."

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

    General

        We are a midstream logistics and marketing company. We are one of the largest distributors of gasoline (including gasoline blendstocks such as ethanol and naphtha), distillates (such as home heating oil, diesel and kerosene), residual oil and renewable fuels to wholesalers, retailers and commercial customers in the New England states and New York. We also engage in the purchasing, selling and logistics of transporting domestic and Canadian crude oil and other products via rail, establishing a "virtual pipeline" from the mid-continent region of the United States and Canada to the East and West Coasts for distribution to refiners and other customers. We own, control or have access to one of the largest terminal networks of refined petroleum products and renewable fuels in the Northeast. We also own and control terminals in North Dakota and Oregon that extend our origin-to-destination capabilities. We are a major multi-brand gasoline distributor and, as of December 31, 2013, had a portfolio of approximately 900 owned, leased and/or supplied gasoline stations primarily in the Northeast. We receive revenue from retail sales of gasoline, convenience store sales and gasoline station rental income. We are also a distributor of natural gas and propane.

        We purchase refined petroleum products, renewable fuels, crude oil, natural gas and propane primarily from domestic and foreign refiners and ethanol producers, crude oil producers, major and independent oil companies and trading companies, and we sell these products in three reporting segments: (i) Wholesale, (ii) Gasoline Distribution and Station Operations and (iii) Commercial which are discussed below.

        Collectively, we sold approximately $19.4 billion of refined petroleum products, renewable fuels, crude oil, natural gas and propane for the year ended December 31, 2013. In addition, we had other revenues of approximately $146.5 million, primarily from convenience store sales at our directly operated stores and rental income from dealer leased or commission agent leased gasoline stations. As of December 31, 2013, we owned, leased or maintained dedicated storage facilities at 26 petroleum product bulk terminals, each with the capacity of more than 50,000 barrels, including 22 refined product terminals located throughout the Northeast. These terminals are supplied primarily by marine transport, pipeline, rail and/or truck and collectively have approximately 10.2 million barrels of storage capacity. In addition to refined products, we have storage capacity at our Albany, New York, Clatskanie, Oregon and North Dakota terminals to store crude oil, at an Albany, New York terminal to store propane and at select locations to store renewable fuels. In Columbus, North Dakota we constructed a 100,000 barrel storage tank and a truck offloading facility in 2012 and a 170,000 barrel storage tank in 2013 used as part of the development of that location as a hub for the gathering, storage, transportation and marketing of crude oil and other products. In Beulah, North Dakota, through Basin Transload LLC, we constructed two 140,000 barrel storage tanks and a truck offloading facility used as part of the development of that location as a hub for gathering, storage, transportation and marketing of crude oil and other products. We also have throughput and exchange agreements at numerous bulk terminals and inland storage facilities. We lease a fleet of rail cars which are utilized in the transporting of crude oil and other products by rail. In addition, we have storage agreements at several of our terminals granting storage rights to third parties for which we receive a fee.

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        In September 2013, our Columbus, North Dakota transloading facility began receiving crude oil from a newly completed seven-mile pipeline lateral connection constructed by Tesoro Logistics, which transports crude oil from various gathering points along the Tesoro High Plains Pipeline System. Also, in 2013, we completed construction in Albany, New York of a new rail-fed propane storage and distribution facility near our existing terminal in Albany, New York and in April, we began receiving and distributing product from the facility. The 540,000-gallon facility can source propane directly from Midwest and Canadian regional sources via single line haul on Canadian Pacific as well as from the East Coast. In addition, construction of a compressed natural gas loading station in Bangor, Maine was completed, and we have established a multi-year agreement with Bangor Gas to supply natural gas to the facility.

        Like most independent marketers, we base our pricing on spot prices, fixed prices or indexed prices and routinely use the NYMEX, CME, ICE or other counterparties to hedge the risk inherent in buying and selling commodities. Through the use of regulated exchanges or derivatives, we seek to maintain a position that is substantially balanced between purchased volumes and sales volumes or future delivery obligations.

    Wholesale

        We engage in the logistics of gathering, storage, transportation and marketing of refined petroleum products, renewable fuels, crude oil and propane. In February 2013, we acquired a 60% membership interest in Basin Transload, which operates two transloading facilities in Columbus and Beulah, North Dakota for crude oil and other products, and 100% of the membership interest in Cascade Kelly, which owns a West Coast crude oil transloading and ethanol manufacturing facility near Portland, Oregon. In January 2013, we signed a five-year contract with Phillips 66 under which we use our storage, rail transloading, logistics and transportation system to deliver crude oil from the Bakken region to Phillips 66's Bayway, New Jersey refinery.

        We own, control or have access to one of the largest terminal networks of refined petroleum products and renewable fuels in the Northeast. We also own and control terminals in North Dakota and Oregon that extend our origin-to-destination capabilities. Our strategically located terminal assets, logistics capabilities, transloading facilities and access to railroad and barge transportation provide a "virtual pipeline" solution for the transportation of crude oil, renewable fuels and other products from the mid-continent region of the United States and Canada to the East and West Coasts.

        This reportable segment includes sales of unbranded gasoline (including gasoline blendstocks such as ethanol and naphtha) and diesel to unbranded gasoline customers and other resellers of transportation fuels, home heating oil, diesel, kerosene, residual oil and propane to home heating oil retailers and wholesale distributors and crude oil to refiners.

        In our Wholesale segment, we obtain Renewable Identification Numbers ("RINs") in connection with our purchase of ethanol either to be used for bulk trading purposes or for blending with gasoline through our terminal system. A RIN is a renewable identification number associated with government-mandated renewable fuel standards. To evidence that the required volume of renewable fuel is blended with gasoline, obligated parties must retire sufficient RINs to cover their Renewable Volume Obligation ("RVO"). Our EPA obligations relative to renewable fuel reporting are largely limited to the foreign gasoline that we may choose to import.

    Gasoline Distribution and Station Operations

        As of December 31, 2013, we had a portfolio of approximately 900 owned, leased and/or supplied gasoline stations primarily in the Northeast. In September 2010, we completed the acquisition from ExxonMobil Corporation of 190 retail gasoline stations, together with the rights to (i) supply Mobil-branded fuel to those stations as well as an additional 31 existing locations in Massachusetts, New

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Hampshire and Rhode Island, and (ii) expand supply opportunities for Mobil-branded and Exxon-branded fuel in certain other New England states. This acquisition expanded our wholesale supply business and added vertical integration to our transportation fuel business in New England. On March 1, 2012, we acquired Alliance, a gasoline distributor and operator of gasoline stations and convenience stores. As of the date of the acquisition, Alliance's portfolio included approximately 540 gasoline stations in the Northeast, of which it owned or held under long-term lease approximately 250 stations and had supply contracts for the remaining stations. The Alliance acquisition expanded our geographic footprint for gasoline stations to include Connecticut, New Jersey, New York, Pennsylvania, Maine and Vermont. Alliance is a top-tier distributor of multiple brands, including Exxon, Mobil, Shell, Sunoco, CITGO and Gulf. Prior to the closing of the acquisition, Alliance was wholly owned by AE Holdings which, on March 1, 2012, was 95% owned by members of the Slifka family.

        On April 26, 2012, we entered into an agreement with Getty Realty to supply and provide management services to more than 200 of its gasoline stations in New York and New Jersey. On November 19, 2012, we signed a long-term lease agreement with Getty Realty for approximately 90 of those 200 sites, which enables us to supply gasoline to and operate gasoline stations, primarily in the New York City boroughs of Queens, Manhattan and the Bronx as well as in Long Island and Westchester County. As of December 31, 2013, the supply and management agreement with respect to the remaining sites expired in accordance with the terms of the agreement.

        This reportable segment includes sales of branded and unbranded gasoline to gasoline stations and other sub-jobbers as well as gasoline, convenience store, car wash and other ancillary sales at our directly operated stores and rental income from dealer leased or commission agent leased retail gasoline stations.

    Commercial

        This segment includes sales and deliveries to end user customers in the public sector and to large commercial and industrial end users of unbranded gasoline, home heating oil, diesel, kerosene, residual oil, renewable fuels and natural gas. 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 barge or from a terminal dock to ships through bunkering activity. For the years ended December 31, 2013, 2012 and 2011, the Commercial operating segment did not meet the quantitative metrics for disclosure as a reportable segment on a stand-alone basis. However, we have elected to present segment disclosures for the Commercial operating segment as we believe such disclosures are meaningful to the user of our financial information.

    Products and Operational Structure

        Our products primarily include gasoline, distillates, residual oil, renewable fuels, crude oil, natural gas and propane. We sell gasoline to branded and unbranded gasoline stations and other resellers of transportation fuels, as well as to customers in the public sector. 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 receive crude oil in the mid-continent region of the United States and Canada and aggregate crude oil by truck or pipeline in the mid-continent, transport it on land by train and ship it to refineries on the East and West Coasts in barges. 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 sell our natural gas to end users and our propane to home heating oil retailers and wholesale distributors.

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        Due to the nature of our business and our reliance, in part, on consumer travel and spending patterns, we may experience more demand for gasoline and gasoline blendstocks during the late spring and summer months than during the fall and winter. Travel and recreational activities are typically higher in these months in the geographic areas in which we operate, increasing the demand for gasoline and gasoline blendstocks that we distribute. Therefore, our volumes in gasoline and gasoline blendstocks are typically higher in the second and third quarters of the calendar year. 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, heating oil and residual oil sales are generally higher during the first and fourth quarters of the calendar year. These factors may result in significant fluctuations in our quarterly operating results.

        Generally, our wholesale customers use their own vehicles or contract carriers to take delivery of the gasoline and distillate products at bulk terminals and inland storage facilities that we own or control or with which we have throughput or exchange arrangements. Our crude oil is aggregated by truck or pipeline in the mid-continent, transported on land by train and shipped to refineries on the East and West Coasts in barges. Ethanol is shipped primarily by rail and by barge. For our commercial customers, we generally arrange the delivery of the product to the customer's designated location, typically hiring third-party common carriers to deliver the product.

    Outlook

        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:

    Our business is influenced by the overall forward market for refined petroleum products, renewable fuels and crude oil, and increases and/or decreases in the prices of these products may adversely impact our financial condition, results of operations and cash available for distribution to our unitholders and the amount of borrowing available for working capital under our credit agreement  Results from our purchasing, storing, terminalling, transporting and selling operations are influenced by prices for refined petroleum products, renewable fuels and crude oil, pricing volatility and the market for such products. Prices in the overall forward market for these products may affect our financial condition, results of operations and cash available for distribution to our unitholders. Our margins can be significantly impacted by the forward product pricing curve, often referred to as the futures market. We typically hedge our exposure to petroleum product and renewable fuel price moves with futures contracts and, to a lesser extent, swaps. In markets where futures prices are higher than current prices, referred to as contango, 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 markets where futures prices are lower than current prices, referred to as backwardation, inventories can depreciate in value and hedging costs are more expensive. For this reason, in these backward markets, we attempt to reduce our inventories in order to minimize these effects. When prices for the products we sell 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 operations. Higher prices for the products we sell 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. When prices for the products we sell decline, our exposure to risk of

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      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 the products we sell at the then lower market price from a competitor. A significant decrease in the price for crude oil could adversely affect the economics of the domestic crude oil production for the product which, in turn, could have an adverse effect on our crude oil logistics activities and sales.

    We commit substantial resources to pursuing acquisitions, although there is no certainty that we will successfully complete any acquisitions or receive the economic results we anticipate from completed acquisitions.  We are continuously engaged in discussions with potential sellers and lessors of existing (or suitable for development) terminalling, storage, logistics and/or marketing assets, including gasoline stations, and related businesses. Our growth largely depends on our ability to make accretive acquisitions and/or accretive development projects. We may be unable to execute such accretive transactions for a number of reasons, including, but not limited to, the following: (1) we are unable to identify attractive transaction candidates or negotiate acceptable terms; (2) we are unable to obtain financing for such transactions on economically acceptable terms; or (3) we are outbid by competitors. In addition, we may consummate transactions 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 and ability to increase distributions could be limited. We can give no assurance that our efforts will be successful or that any such transaction will be completed on terms that are favorable to us.

    The condition of credit markets may adversely affect our liquidity.  In the past, world financial markets experienced a severe reduction in the availability of credit. 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 depend upon rail and marine transportation services for a substantial portion of our logistics business in transporting the products we sell. A disruption in rail and marine transportation services could have an adverse effect on our financial condition, results of operations and cash available for distribution to our unitholders.  Hurricanes, flooding and other severe weather conditions could cause a disruption in the transportation services we depend on which could affect the flow of service. In addition, accidents, labor disputes between the railroads and their union employees and labor renegotiations or a work stoppage at railroads could also disrupt rail service. These events could result in service disruptions and increased cost which could also adversely affect our financial condition, results of operations and cash available for distribution to our unitholders. Other disruptions, such as those due to an act of terrorism or war, could also adversely affect our business.

    Our gasoline and gasoline blendstocks financial results are seasonal and generally lower in the first and fourth quarters of the calendar year.  Due to the nature of our business and our reliance, in part, on consumer travel and spending patterns, we may experience more demand for gasoline and gasoline blendstocks during the late spring and summer months than during the fall and winter. Travel and recreational activities are typically higher in these months in the geographic areas in which we operate, increasing the demand for gasoline and gasoline blendstocks that we distribute. Therefore, our results of operations in gasoline and gasoline blendstocks are typically lower in the first and fourth quarters of the calendar year.

    Our heating oil and residual oil financial results are seasonal and generally lower in the second and third 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

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      these sales during the winter months. Therefore, our results of operations in heating oil and residual oil for the first and fourth calendar quarters are generally better than for the second and third quarters.

    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 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, higher prices, 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. During periods of increasing home heating oil prices relative to the price of 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, higher prices and 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.

    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 EPA's regulations on the RFS program and oxygenate blending requirements. A reduction or waiver of the RFS mandate or oxygenate blending requirements could adversely affect the availability and pricing of ethanol, which in turn could adversely affect our future gasoline and ethanol sales. In addition, changes in blending requirements could affect the price of RINs which could impact the magnitude of the mark-to-market liability recorded for the deficiency, if any, in our RIN position relative to our RVO at a point in time.

    New, stricter environmental laws and regulations could significantly impact our operations and/or 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 operations, 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 over time. 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.

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Results of Operations

    Evaluating Our Results of Operations

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

    Product Margin

        We view product margin as an important performance measure of the core profitability of our operations. We review product margin monthly for consistency and trend analysis. We define product margin as our product sales minus product costs. Product sales primarily include sales of unbranded and branded gasoline, distillates, residual oil, renewable fuels, crude oil, natural gas and propane, as well as convenience store sales, gasoline station rental income and revenue generated from our logistics activities. Product costs include the cost of acquiring the refined petroleum products, renewable fuels, crude oil, natural gas and propane and all associated costs including shipping and handling costs to bring such products to the point of sale as well as product costs related to convenience store items and costs associated with our logistics activities. We also look at product margin on a per unit basis (product margin divided by volume). Product margin is a non-GAAP financial measure used by management and external users of our consolidated financial statements to assess our business. Product margin should not be considered an alternative to net income, operating income, cash flow from operations, or any other measure of financial performance presented in accordance with GAAP. In addition, our product margin may not be comparable to product margin or a similarly titled measure of other companies.

    Gross Profit

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

    EBITDA

        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, storing and distribution of refined petroleum products, renewable fuels, crude oil, natural gas and propane, 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.

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        EBITDA should not be considered as 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

        Distributable cash flow is an important non-GAAP financial measure for our limited partners since they serve as an indicators of our success in providing a cash return on their investment. 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.

    Selling, General and Administrative Expenses

        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

        Operating expenses are costs associated with the operation of the terminals (including the crude oil facilities) 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.

    Net Income Per Diluted Limited Partner Unit

        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, after deducting the amount allocated to noncontrolling interest, divided by the weighted average number of outstanding diluted common units, or limited partner units, during the period.

    Degree Day

        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.

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    Years Ended December 31, 2013, 2012 and 2011

    Significant Activities-2013

        During 2013, we continued to expand our crude oil activities, including:

    On January 1, 2013, we signed a five-year contract with Phillips 66 under which we will use our storage, rail transloading, logistics and transportation system to deliver crude oil from the Bakken region of North Dakota to Phillips 66's Bayway, New Jersey refinery. The terms of the contract include a take-or-pay commitment from Phillips 66 to receive approximately 91 million barrels of crude oil over the contract term.

    On February 1, 2013, we acquired a 60% membership interest in Basin Transload, which operates two transloading facilities in Columbus and Beulah, North Dakota for crude oil and other products, with a then combined rail loading capacity of 160,000 barrels per day.

    On February 15, 2013, we acquired 100% of the membership interests in Cascade Kelly, which owns a West Coast crude oil transloading and ethanol manufacturing facility near Portland, Oregon. The transaction includes a rail transloading facility, 200,000 barrels of storage capacity, a deepwater marine terminal with access to a 1,200-foot leased dock and the largest ethanol plant on the West Coast.

    In September 2013, our Columbus, North Dakota transload facility began receiving crude oil from a newly completed seven-mile pipeline lateral connection constructed by Tesoro Logistics, which transports crude oil from various gathering points along the Tesoro High Plains Pipeline System.

        Also, in 2013, we completed construction in Albany, New York of a new rail-fed propane storage and distribution facility near our existing terminal in Albany, New York and in April, we began receiving and distributing product from the facility. The 540,000-gallon facility can source propane directly from Midwest and Canadian regional sources via single line haul on Canadian Pacific as well as from the East Coast. In addition, construction of a compressed natural gas loading station in Bangor, Maine was completed, and we have established a multi-year agreement with Bangor Gas to supply natural gas to the facility.

    Significant Activities-2012

        During 2012, we continued to expand our Gasoline Distribution and Station Operations segment. On March 1, 2012, we acquired Alliance, a gasoline distributor and operator of gasoline stations and convenience stores. As of the date of the acquisition, Alliance's portfolio included approximately 540 gasoline stations in the Northeast, of which it owned or held under long-term lease approximately 250 stations, and had supply contracts for the remaining stations. The Alliance acquisition expanded our geographic footprint for gasoline stations to include Connecticut, New Jersey, New York, Pennsylvania, Maine and Vermont. Alliance is a top-tier distributor of multiple brands, including Exxon, Mobil, Shell, Sunoco, CITGO and Gulf.

        On April 26, 2012, we entered into an agreement with Getty Realty to supply and provide management services to more than 200 of its gasoline stations in New York and New Jersey. On November 19, 2012, we signed a long-term lease agreement with Getty Realty for approximately 90 of those 200 sites to supply and operate gasoline station in the New York City boroughs of Queens, Manhattan and the Bronx as well as in Long Island and Westchester County. The initial lease term for the locations is 15 years and includes multiple five-year renewal options. The lease with Getty Realty significantly expands our retail gasoline and fuel distribution presence in the New York metro region.

        In our Wholesale segment, we continued our expansion into crude oil logistics, including the gathering, storage, transportation and marketing of crude oil. We completed construction on our new

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100,000 barrel tank and truck offloading facility in Columbus, North Dakota as part of the development of that location as a hub for the gathering, storage, transportation and marketing of crude oil and other products. In addition, in Albany, New York, we completed a build-out project that increased rail receipts and throughput storage capacities of ethanol and crude oil and converted certain storage tanks for the handling of crude oil. This expansion increased our capacity to receive and distribute crude oil and other products from the mid-continent from 55,000 barrels per day to 160,000 barrels per day and allows the terminal to offload two 120-car unit trains in a 24-hour period. Our rail expansion serves to enhance our "virtual pipeline" solution for the transportation of crude oil and other products from the mid-continent region to Albany. Our rail shipments to Albany average four to five days, with some shipments completed in as little as two and a half days. From Albany, it is then a one to one and a half day trip by barge to the East Coast refineries.

    Significant Activities-2011

        In 2011, we continued initiating organic expansion projects. For example, in part, we (i) converted 230,000 barrels of storage capacity at our Albany, New York terminal that are utilized for either distillates or gasoline; (ii) brought into service an additional 200,000 barrels of distillates and crude oil storage capacity at this facility and (iii) converted two tanks to handle bio-fuel at our Providence, Rhode Island terminal.

        In March 2011, and pursuant to our 15-year brand fee agreement with ExxonMobil, which provides us with the ability to provide Mobil-branded fuel to other authorized Mobil distributors ("Mobil Sub-jobbers"), we began supplying Mobil-branded fuel to Mobil Sub-jobbers, including Alliance, in Massachusetts, New Hampshire, Rhode Island and Maine.

        In the fourth quarter of 2011, we began buying mid-continent crude oil and transporting it by rail to our Albany, New York terminal for storage and subsequent sale in barge load quantities. We also initiated a project to store product in North Dakota.

    Events That Impacted Results

        During the year ended December 31, 2013, we experienced the following events:

    We recognized the results of the Alliance acquisition for the full year compared to a ten-month period in 2012 as we acquired Alliance on March 1, 2012.

    In our Wholesale segment, our product margin from gasoline and gasoline blendstocks sales decreased for 2013 compared to 2012, due, in part, to the effect of increases in the liability related to RIN forward commitments of $6.2 million and in the mark to market value of the RVO Deficiency of $13.1 million, resulting in a $19.3 million unfavorable impact for 2013. While there was increased competition in gasoline during most of 2013, which negatively impacted margins, market conditions were favorable in the second and fourth quarters.

    During 2013, in part through the Phillip 66 transaction and the February 2013 acquisitions of a 60% membership interest in Basin Transload and a 100% membership interest in Cascade Kelly, we continued our expansion into crude oil logistics which improved our crude oil product margin. Despite the increase, our crude oil product margin was negatively impacted by temporary supply dislocations in the crude oil market during the third quarter of 2013.

    We continued to expand our wholesale gasoline and gasoline blendstocks and distillates businesses by expanding terminal throughput and sales locations at third-party facilities across the country.

    In our Gasoline Distribution and Station Operations segment, rising gasoline prices typically compress our gasoline product margins and declining gasoline prices typically improve our

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      gasoline product margins. The extent of the impact on our product margins depends on the magnitude, duration and direction of the market. Our gasoline product margins were compressed during the first quarter of 2013 due to rising gasoline prices, and our product margins benefited from declining gasoline prices during the third quarter. The following chart provides the RBOB NYMEX gasoline prices during 2013:


GRAPHIC
    Operating expenses increased by $45.3 million for 2013 compared to 2012, primarily due to the February 2013 acquisitions of Basin Transload and Cascade Kelly and the March 2012 acquisition of Alliance.

    Our depreciation allocated to cost of sales, which impacts our gross profit, increased by approximately $19.0 million for 2013 compared to 2012, primarily due to the February 2013 acquisitions of Basin Transload and Cascade Kelly and the March 2012 acquisition of Alliance.

    Temperatures for 2013 were 16% colder than 2012 which increased demand for our weather-related products and improved our Wholesale and Commercial product margins.

    Our product margins for 2013 were also affected by a variety of other factors, such as changes in commodity prices, movement of products between foreign locales and within the United States, changes in refiner demand, weekly and monthly refinery output levels, changes in local, domestic and worldwide inventory levels, seasonality, supply, weather and logistics disruptions.

        During the year ended December 31, 2012, we experienced the following events:

    In our Gasoline Distribution and Station Operations segment, our sales, volume and product margin significantly increased due primarily to our acquisition of Alliance, as well as a full year of sales of Mobil-branded fuel to Mobil Sub-jobbers and to the Getty Realty agreements.

    In our Wholesale segment, our continued expansion into crude oil logistics, including the gathering, storage, transportation and marketing of crude oil, improved our Wholesale segment product margin.

    We believe our wholesale gasoline business was negatively impacted by a challenging futures market, which increased our hedging costs for 2012, and less favorable buying opportunities which reduced our wholesale gasoline product margin.

    We believe our wholesale distillate business was negatively impacted due to less favorable buying opportunities and warmer weather in 2012 compared to 2011.

    The price for heating oil at December 31, 2012 compared to the price at December 31, 2011 increased by 4%. We believe heating oil conservation and conversions to natural gas continued during 2012.

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    Temperatures for 2012 were 16% warmer than normal and 7% warmer than 2011 which negatively affected demand for our weather-related products during the year.

    In connection with the acquisition of Alliance, we had one-time acquisition costs of approximately $4.0 million for 2012.

    Our interest expense increased by 17% for 2012, due primarily to additional borrowings associated with the acquisition of Alliance.

    In our Gasoline Distribution and Station Operations segment, our gasoline product margins were compressed during the first and third quarters of 2012 due to rising gasoline prices, and our product margins improved during the second and fourth quarters due to declining gasoline prices. The following chart provides the RBOB NYMEX gasoline prices during 2012:


GRAPHIC
    Our product margins for 2012 were also affected by a variety of other factors, such as movement of products between Europe and the United States, weekly and monthly refinery output levels, changes in local, domestic and worldwide inventory levels, seasonality and supply disruptions.

        During 2011, we experienced the following events:

    Refined petroleum product and renewable fuel prices rose during 2011.

    Temperatures for 2011 were 9% warmer than normal.

    We increased our reserve for bad debts by approximately $1.9 million for 2011, substantially due to specific risks related to one customer.

    We reduced our workforce by approximately 10% which resulted in restructuring charges of approximately $2.0 million for 2011.

    We believe heating oil conservation and conversions to natural gas continued during 2011.

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

    We believe our margins for 2011 were negatively impacted by less favorable market conditions and fewer advantageous purchasing opportunities in our distillates business and by a backward forward product pricing curve in our wholesale gasoline business.

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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 (in thousands, except per unit data):

 
  Year Ended December 31,  
 
  2013   2012   2011  

Net income attributable to Global Partners LP

  $ 42,615   $ 46,743   $ 19,352  

Net income per diluted limited partner unit (1)

  $ 1.52   $ 1.71   $ 0.87  

EBITDA (2)

  $ 157,394   $ 135,799   $ 85,711  

Distributable cash flow (3)

  $ 105,254   $ 80,769   $ 46,741  

Wholesale Segment (4)(10):

                   

Volume (gallons)

    5,507,829     4,793,538     4,436,117  

Sales

                   

Gasoline and gasoline blendstocks

  $ 8,085,225   $ 8,827,621   $ 8,660,412  

Crude oil (5)

    3,561,428     1,205,588     40,873  

Other oils and related products (6)

    3,559,001     3,727,701     3,895,632  
               

Total

  $ 15,205,654   $ 13,760,910   $ 12,596,917  

Product margin

                   

Gasoline and gasoline blendstocks

  $ 43,147   $ 54,639   $ 56,224  

Crude oil (5)

    92,807     35,538     12,301  

Other oils and related products (6)

    66,916     55,252     55,308  
               

Total

  $ 202,870   $ 145,429   $ 123,833  

Gasoline Distribution and Station Operations Segment (7):

                   

Volume (gallons)

    1,047,120     954,315     442,879  

Sales

                   

Gasoline

  $ 3,231,925   $ 3,024,775   $ 1,404,988  

Station operations (8)

    146,503     124,131     58,786  
               

Total

  $ 3,378,428   $ 3,148,906   $ 1,463,774  

Product margin

                   

Gasoline

  $ 150,147   $ 139,706   $ 56,690  

Station operations (8)

    80,106     66,384     31,491  
               

Total

  $ 230,253   $ 206,090   $ 88,181  

Commercial Segment:

                   

Volume (gallons)

    401,482     352,210     338,210  

Sales

  $ 1,005,526   $ 716,181   $ 775,038  

Product margin

  $ 28,359   $ 18,652   $ 21,975  

Combined sales and product margin:

                   

Sales

  $ 19,589,608   $ 17,625,997   $ 14,835,729  

Product margin (9)

  $ 461,482   $ 370,171   $ 233,989  

Depreciation allocated to cost of sales

    (55,653 )   (36,683 )   (24,391 )
               

Combined gross profit

  $ 405,829   $ 333,488   $ 209,598  
               
               

Weather conditions:

                   

Normal heating degree days

    5,630     5,661     5,630  

Actual heating degree days

    5,521     4,754     5,137  

Variance from normal heating degree days

    (2% )   (16% )   (9% )

Variance from prior period actual heating degree days

    16%     (7% )   2%  

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

(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.

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(3)
Distributable cash flow is a non-GAAP financial measures 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)
Segment reporting results for the prior periods have been reclassified to conform to our current presentation.

(5)
Crude oil consists of our crude oil sales and revenue from our logistics activities and includes the February 2013 acquisitions of Basin Transload and Cascade Kelly (see Note 3 of Notes to Consolidated Financial Statements). As the Basin Transload and Cascade Kelly assets were not in place for a portion of the year ended December 31, 2013 or for any portion of the years ended December 31, 2012 and 2011, the above results are not directly comparable for periods prior to February 2013.

(6)
Other oils and related products primarily consist of distillates, residual oil and propane.

(7)
On March 1, 2012, we completed our acquisition of Alliance. As these assets were not in place for a portion of the year ended December 31, 2012 or for any portion of the year ended December 31, 2011, the above results are not directly comparable for periods prior to March 1, 2012.

(8)
Station operations primarily consist of convenience store sales at our directly operated stores and rental income from dealer leased or commission agent leased gasoline stations.

(9)
Product margin is a non-GAAP financial measure which is discussed above under "—Evaluating Our Results of Operations." The table above includes a reconciliation of product margin on a combined basis to gross profit, a directly comparable GAAP financial measure.

(10)
We evaluated the impact of the 2013 acquisitions and concluded there were no changes to the reportable segments. The operating results of Basin Transload and Cascade Kelly subsequent to the date of acquisition are included in the Wholesale segment.

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

 
  Year Ended December 31,  
 
  2013   2012   2011  

Reconciliation of net income to EBITDA:

                   

Net income

  $ 41,053   $ 46,743   $ 19,352  

Net loss attributable to noncontrolling interest

    1,562          
               

Net income attributable to Global Partners LP

    42,615     46,743     19,352  

Depreciation and amortization, excluding the impact of noncontrolling interest

    70,423     45,458     30,359  

Interest expense

    43,537     42,021     35,932  

Income tax expense

    819     1,577     68  
               

EBITDA

  $ 157,394   $ 135,799   $ 85,711  
               
               

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

   
 
   
 
   
 
 

Net cash provided by (used in) operating activities

  $ 255,147   $ 232,452   $ (17,357 )

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

    (136,960 )   (140,251 )   67,068  

Net cash from operating activities and changes in operating assets and liabilities attributable to noncontrolling interest

    (5,149 )        

Interest expense

    43,537     42,021     35,932  

Income tax expense

    819     1,577     68  
               

EBITDA

  $ 157,394   $ 135,799   $ 85,711  
               
               

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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):

 
  Year Ended December 31,  
 
  2013   2012   2011  

Reconciliation of net income to distributable cash flow:

                   

Net income

  $ 41,053   $ 46,743   $ 19,352  

Net loss attributable to noncontrolling interest

    1,562          
               

Net income attributable to Global Partners LP

    42,615     46,743     19,352  

Depreciation and amortization, excluding the impact of noncontrolling interest

    70,423     45,458     30,359  

Amortization of deferred financing fees

    6,897     5,753     4,723  

Amortization of senior notes discount

    368          

Amortization of routine bank refinancing fees

    (4,072 )   (4,073 )   (3,467 )

Maintenance capital expenditures

    (10,977 )   (13,112 )   (4,226 )
               

Distributable cash flow

  $ 105,254   $ 80,769   $ 46,741  
               
               

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

   
 
   
 
   
 
 

Net cash provided by (used in) operating activities

  $ 255,147   $ 232,452   $ (17,357 )

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

    (136,960 )   (140,251 )   67,068  

Net cash from operating activities and changes in operating assets and liabilities attributable to noncontrolling interest

    (5,149 )        

Amortization of senior notes discount

    368          

Amortization of deferred financing fees

    6,897     5,753     4,723  

Amortization of routine bank refinancing fees

    (4,072 )   (4,073 )   (3,467 )

Maintenance capital expenditures

    (10,977 )   (13,112 )   (4,226 )
               

Distributable cash flow

  $ 105,254   $ 80,769   $ 46,741  
               
               

    Consolidated Sales

        Our total sales for 2013 increased by $2.0 billion, or 11%, to $19.6 billion compared to $17.6 billion for 2012, primarily due to an increase in volume sold. Our aggregate volume of product sold was 7.0 billion gallons for 2013 compared to 6.1 billion gallons for 2012, an increase of 0.9 billion gallons, or 14%. The increase in volume sold includes an increase of 714 million gallons in our Wholesale segment attributable to increases in crude oil and in distillates due to colder weather year over year, offset by a decrease in gasoline volume due to increased competition. The increase in total volume also includes increases of 93 million gallons in our Gasoline Distribution and Station Operations segment, primarily due to our supply and management agreement and unitary lease with Getty Realty and to the inclusion of Alliance for the full year of 2013 compared to ten months in 2012, and 49 million gallons in our Commercial segment due largely to an increase in bunkering activity. Our gross profit for 2013 was $405.8 million, an increase of $72.3 million, or 22%, compared to $333.5 million for 2012, due primarily to an increase in (i) our crude oil activities, including the Phillips 66 transaction and the February 2013 acquisitions of Basin Transload and Cascade Kelly, (ii) our Gasoline Distribution and Station Operations segment which includes the results of Alliance for the full year of 2013 compared to ten months in 2012, (iii) our wholesale distillates business due to favorable market conditions and colder weather year over year, and (iv) our commercial business due largely to an increase in bunkering activity. Despite the increase, our gross profit was negatively impacted by 2013 events, including (i) a $6.2 million mark to market loss related to RIN forward commitments and a $13.1 million mark to market value of the RVO Deficiency, resulting in a $19.3 million unfavorable impact in our wholesale gasoline and gasoline blendstocks product margin for 2013, (ii) temporary supply dislocations in the crude oil market during the third quarter and (iii) an increase in depreciation, which is included in cost of sales, primarily related to our acquisitions of Basin Transload and Cascade Kelly in February 2013 and Alliance in March 2012.

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        Our total sales for 2012 increased by $2.8 billion, or 19%, to $17.6 billion compared to $14.8 billion for 2011 due to an increase in volume sold. Our aggregate volume of product sold was 6.1 billion gallons for 2012 compared to 5.2 billion gallons for 2011, an increase of 0.9 billion gallons, or 17%. The increase in volume sold includes increases of approximately 511 million gallons in our Gasoline Distribution and Station Operations segment, primarily due to our acquisition in March 2012 of Alliance, 357 million gallons in our Wholesale segment, primarily due to the expansion of crude oil and to an increase in gasoline, offset by a decrease in distillates due to warmer temperatures year over year, and 14 million gallons in our Commercial segment. Our gross profit for 2012 was $333.5 million, an increase of $123.9 million, or 59%, compared to $209.6 million for 2011, due primarily to the Alliance acquisition and to the expansion of crude oil. Notwithstanding the increase, our gross profit was negatively impacted by a challenging futures market, primarily backwardation in the gasoline futures market for most of 2012, and less favorable buying opportunities in wholesale gasoline and gasoline blendstocks and in distillates.

    Wholesale Segment

        Gasoline and Gasoline Blendstocks.    Sales from wholesale gasoline and gasoline blendstocks were $8.1 billion for 2013 compared to $8.8 billion for 2012. The decrease of $0.7 billion, or 8%, was due primarily to a decrease in volume sold due to increased competition. Our product margin from wholesale gasoline and gasoline blendstocks sales decreased by $11.5 million to $43.1 million for 2013 compared to $54.6 million for 2012 due primarily to a $6.2 million mark to market loss related to RIN forward commitments and a $13.1 million mark to market value of the RVO Deficiency. While there was increased competition in gasoline during most of 2013, which negatively impacted margins, market conditions were favorable in the second and fourth quarters.

        Sales from wholesale gasoline and gasoline blendstocks were $8.8 billion for 2012 compared to $8.7 billion for 2011. The increase of $0.1 billion, or 2%, was due to an increase in volume sold attributable to an increase in demand for gasoline and gasoline blendstocks. Our product margin from wholesale gasoline and gasoline blendstocks sales decreased by $1.6 million to $54.6 million for 2012 compared to $56.2 million for 2011, due primarily to a challenging futures market, mainly backwardation which increased hedging costs, less favorable buying opportunities, lower margins in gasoline blendstocks and increased competition.

        Crude Oil.    Sales from crude oil (primarily crude oil sales and logistics revenues) were $3.6 billion for 2013 compared to $1.2 billion for 2012. The increase of $2.4 billion was primarily due to an increase in volume sold and to the addition our logistics activities. Our product margin from crude oil increased by $57.3 million to $92.8 million for 2013 compared to $35.5 million in 2012, primarily due to an increase in our crude oil activities, including the Phillips 66 transaction and the February 2013 acquisitions of Basin Transload and Cascade Kelly. Despite the increase, our product margin for crude oil was negatively impacted due to temporary supply dislocations in the crude oil market during the third quarter of 2013.

        Sales from crude oil were $1.2 billion for 2012 compared to $40.9 million for 2011. Our product margin from crude oil was $35.5 million for 2012 compared to $12.3 million in 2011. The increases of $1.2 billion and $23.2 million in sales and product margin, respectively, were due to a full year of crude oil sales in 2012 versus three months in 2011 as we began offering crude oil during the fourth quarter of 2011.

        Other Oils and Related Products.    Sales from other oils and related products (primarily distillates, residual oil and propane) were $3.5 billion for 2013 compared to $3.7 billion for 2012. The decrease of $0.2 billion for 2013 was primarily due to a decrease in prices and a decrease in residual oil due to increased competition, offset by an increase in distillates due to favorable market conditions and colder weather year over year. In addition, we began offering propane during the second quarter of 2013. Our

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product margin from other oils and related products increased by $11.7 million, or 21%, to $66.9 million for 2013 compared to $55.2 million 2012, due primarily to our distillates business as a result of favorable market conditions and colder weather year over year.

        Sales from other oils and related products were $3.7 billion for 2012 compared to $3.9 billion for 2011. The decrease $0.2 billion, or 5%, was primarily due to a decrease in distillates volume sold. Our product margin from other oils and related products was flat at $55.3 million for 2012 and 2011. Our product margin for distillates improved in 2012 but was negatively impacted due to less favorable buying opportunities and warmer weather in 2012 compared to 2011.

    Gasoline Distribution and Station Operations Segment

        Gasoline Distribution.    Sales from gasoline distribution were $3.2 billion for 2013 compared to $3.0 billion for 2012. The increase of $0.2 billion, or 7% was due primarily to an increase in volume sold as a result of including the results of Alliance for the full year of 2013 compared to ten months in 2012 and to our supply and management agreement and unitary lease with Getty Realty which were not in place for the full year of 2012. Primarily for these same reasons, our product margin increased by $10.4 million to $150.1 million for 2013 compared to $139.7 million for 2012.

        Sales from gasoline distribution were $3.0 billion for 2012 compared to $1.4 billion for 2011. The increase of $1.6 billion, or 115%, was due primarily to an increase in volume sold as a result of our acquisition of Alliance and to a full year of sales of Mobil-branded fuel to Mobil Sub-jobbers pursuant to our brand fee agreement with ExxonMobil, which began in March 2011, as well as the Getty Realty agreements. For these same reasons, our product margin from gasoline distribution increased by $83.0 million to $139.7 million for 2012 compared to $56.7 million for 2011.

        Station Operations.    Our station operations, which consist primarily of convenience stores sales at our directly operated stores and rental income from dealer leased or commission agent leased gasoline stations, collectively generated revenues of approximately $146.5 million, $124.1 million and $58.8 million for 2013, 2012 and 2011, respectively. Our product margin from station operations was $80.1 million, $66.4 million and $31.5 million for 2013, 2012 and 2011, respectively. The increases in revenues and product margin for 2013 compared 2012 were due primarily due to including the results of the Alliance acquisition for a full year in 2013 versus ten months in 2012. The increases in revenues and product margin for 2012 compared to 2011 are due primarily to the Alliance acquisition in March 2012.

    Commercial Segment

        Our commercial sales were $1.0 billion, $0.7 billion and $0.8 billion for 2013, 2012 and 2011, respectively. Our commercial product margin was $28.4 million, $18.7 million and $22.0 million for 2013, 2012 and 2011, respectively. The increases in sales and product margin for 2013 compared 2012 were primarily due to an increase in bunkering activity. In our Commercial segment, residual oil accounted for approximately 51%, 41% and 47% of our total commercial volume sold for 2013, 2012 and 2011, respectively. Distillates, gasoline and natural gas accounted for the remainder of the total commercial sales, volume sold and product margin.

    Selling, General and Administrative Expenses

        SG&A expenses increased by $19.8 million, or 21%, to $115.5 million for 2013 compared to $95.7 million for 2012. The increase includes increases of $14.8 million in professional fees and due diligence costs associated with the growth of our business, including the acquisitions of Basin Transload and Cascade Kelly, $5.9 million in overhead expenses to support the growth of our business, $3.4 million in bad debt expense, $1.3 million in incentive compensation, and $3.2 million in other SG&A expenses. The overall increase in SG&A expenses for 2013 includes additional costs to support

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the growth of our business, primarily related to our crude oil activities and, expenses related to our retail gasoline stations for a full year of 2013 versus ten months in 2012. The increase in SG&A expenses was offset by a decrease of $3.2 million in commissions related to certain gasoline station operations and $1.2 million in bank and letter of credit fees. In addition, in 2012, we had costs related to Alliance that did not recur in 2013, specifically $4.0 million in one-time acquisition costs and $0.4 million in management fees related to management agreements with Alliance that terminated in connection with the acquisition.

        SG&A expenses increased by $21.8 million, or 29%, to $95.7 million for 2012 compared to $73.9 million for 2011, primarily due to the addition of Alliance. The increase includes increases of $12.7 million in overhead expenses, $4.0 million in one-time acquisition costs related to the acquisition of Alliance, $2.6 million in bank fees, $2.0 million in accrued incentive compensation and $5.2 million in various other SG&A expenses, offset by decreases of $2.2 million in management fees related to management agreements with Alliance which agreements terminated as a result of the Alliance acquisition, $1.1 million in bad debt expense and $1.4 million in professional fees.

    Operating Expenses

        Operating expenses increased by $45.3 million, or 32%, to $185.7 million for 2013 compared to $140.4 million for 2012. The increase in operating expenses includes $24.4 million in costs related to the operations of our retail gasoline stations for a full year of 2013 versus ten months in 2012, including expenses associated with management of the Getty Realty locations, $17.8 million in costs associated with our crude oil operations, largely reflecting our 2013 acquisitions of Basin Transload and Cascade Kelly, $2.6 million in operating costs associated with our terminals in Albany, New York, in part due to the addition of our propane facility, and $2.9 million in other operating expenses. The increase in operating expenses was offset by a $2.4 million decrease in expenses at our East Providence, Rhode Island terminal as our lease expired in April 2013, and we elected not to renew.

        Operating expenses increased by $66.9 million, or 91%, to $140.4 million for 2012 compared to $73.5 million for 2011. The increase was primarily due to $61.8 million in costs related to the operations of the gasoline stations acquired from Alliance in March 2012 and expenses associated with management of the Getty Realty locations. The increase in operating expenses also includes $2.3 million related to our Albany, New York terminals, $0.9 million related to our Newburgh, New York terminals, and $0.2 million in various other operating expenses. In addition, during the second quarter of 2011, we had a $1.7 million one-time reduction in our environmental reserve with respect to the Albany, New York terminal, which was recorded as a reduction to operating expenses.

    Amortization Expense

        Amortization expense related to our intangible assets was $19.2 million, $7.0 million and $4.8 million for 2013, 2012 and 2011, respectively. The increase of $12.2 million for 2013 compared to 2012 was primarily due to $26.2 million of intangible assets acquired in the Basin Transload acquisition and to a full year of amortization in 2013 versus ten months in 2012 related to the intangible assets acquired in the Alliance acquisition. The increase of $2.2 million for 2012 compared to 2011 was due to $31.1 million of intangible assets acquired in the Alliance acquisition in March 2012.

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    Restructuring Charges

        During the third quarter of 2011, we reduced our workforce by approximately 10% which resulted in restructuring charges of approximately $2.0 million for 2011. These restructuring charges consist principally of severance and outplacement costs for terminated employees. We paid a total of $2.0 million in restructuring charges through December 31, 2013. There were no similar reductions in workforce in 2013 or 2012.

    Interest Expense

        Interest expense was $43.5 million, $42.0 million and $35.9 million for 2013, 2012 and 2011, respectively. The $1.5 million increase in 2013 compared to 2012 was due primarily to additional borrowings related to our February 2013 acquisitions of Basin Transload and Cascade Kelly and our March 2012 acquisition of Alliance and a $1.1 million increase in amortization of deferred financing fees, offset by lower working capital borrowings and a decrease in costs of borrowings in connection with the November 2012 amendment to our credit agreement. The $6.1 million increase in interest expense in 2012 compared to 2011 was due to additional borrowings related to the acquisition of Alliance and a $1.0 million increase in amortization of deferred financing fees.

    Income Tax Expense

        Income tax expense was $0.8 million, $1.6 million and $68 thousand for 2013, 2012 and 2011, respectively. The income tax expense is due to the operating results of our wholly-owned subsidiary, Global Montello Group Corp., which is a taxable entity for federal and state income tax purposes.

    Net Loss Attributable to Noncontrolling Interest

        On February 1, 2013, we acquired a 60% membership interest in Basin Transload. The net loss attributable to noncontrolling interest of $1.6 million for 2013 represents Basin Transload's 40% interest.

Liquidity and Capital Resources

    Liquidity

        Our primary liquidity needs are to fund our working capital requirements, capital expenditures and distributions and to service our indebtedness. Cash generated from operations and our working capital revolving credit facility provide our primary sources of liquidity. Working capital decreased by $60.0 million to $401.7 million at December 31, 2013 compared to $461.7 million at December 31, 2012, in part due to changes in accounts receivable, inventories, accounts payable, accrued liabilities for the RVO Deficiency of $13.1 million and the mark to market value of RIN forward commitments of $6.2 million and to the addition of the term loan.

        On February 14, 2013, we paid a cash distribution to our common unitholders and our general partner of approximately $16.3 million for the fourth quarter of 2012. On May 15, 2013, we paid a cash distribution to our common unitholders and our general partner of approximately $16.8 million for the first quarter of 2013. On August 14, 2013, we paid a cash distribution to our common unitholders and our general partner of approximately $17.0 million for the second quarter of 2013. On November 14, 2013, we paid a cash distribution to our common unitholders and our general partner of approximately $17.4 million for the third quarter of 2013. On February 14, 2014, we paid a cash distribution to our common unitholders and our general partner of approximately $17.9 million for the fourth quarter of 2013.

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    Contractual Obligations

        We have contractual obligations that are required to be settled in cash. The amounts of our contractual obligations at December 31, 2013 were 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)

  $ 862,494   $ 31,701   $ 380,817   $ 449,976   $  

Senior notes (2)

    208,300     11,800     23,600     172,900      

Operating lease obligations (3)

    562,480     95,370     188,391     127,649     151,070  

Capital lease obligations

    826     176     352     298      

Other long-term liabilities (4)

    206,345     33,954     68,145     40,768     63,478  
                       

Total

  $ 1,840,445   $ 173,001   $ 661,305   $ 791,591   $ 214,548  
                       
                       

(1)
Includes principal and interest on our working capital revolving credit facility and our revolving credit facility at December 31, 2013 and assumes a ratable payment through the expiration date. Our credit agreement has a contractual maturity of April 30, 2018 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 principal and interest on our 8.00% senior notes due in February 2018 and our 7.75% senior notes due in December 2018. No principal payments are required prior to maturity.

(3)
Includes operating lease obligations related to leases for office space and computer equipment, land, terminals and throughputs, gasoline stations, railcars, mobile equipment, access rights and a lease with a related party.

(4)
Includes amounts related to our 15-year brand fee agreement entered into in 2010 with ExxonMobil, minimum freight requirements on the transportation of crude oil and ethanol to our Albany, New York terminal and pension and deferred compensation obligations.

        In addition to the obligations described in the above table, we had minimum volume purchase requirements at December 31, 2013. Pricing is based on spot prices at the time of purchase. Please read Note 13 of Notes to Consolidated Financial Statements with respect to purchase commitments and sublease information related to certain lease agreements.

    Capital Expenditures

        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 anticipate that maintenance capital expenditures will be funded with cash generated by operations. We had approximately $11.0 million, $13.1 million and $4.2 million in maintenance capital expenditures for the years ended December 31, 2013, 2012 and 2011, respectively, which are included in capital expenditures in the accompanying consolidated statements of cash flows. The increases in maintenance capital expenditures in 2013 and 2012 compared to 2011 were primarily due to additional expenditures related to our gasoline stations. 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.

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        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, for example, rail capacity, dock capacity and tankage, diversifying product availability and storage flexibility 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 debt securities or additional equity. We had approximately $146.2 million, $332.5 million and $11.7 million in expansion capital expenditures for the years ended December 31, 2013, 2012 and 2011, respectively, which are included in capital expenditures in the accompanying consolidated statements of cash flows.

        Specifically, for 2013, expansion capital expenditures included approximately $90.0 million in property and equipment associated with the acquisitions of Cascade Kelly and a 60% membership interest in Basin Transload. In addition, we had $56.1 million in expansion capital expenditures which consists of $23.6 million in costs associated with our crude oil activities, $22.6 million in new site development, expansion and improvements at certain retail gasoline stations, $4.5 million in costs associated with the building of a propane storage and distribution facility in Albany, New York and $5.4 million in other expansion capital expenditures including, in part, construction costs at our compressed natural gas loading station in Bangor, Maine and terminal equipment and computer upgrades at various terminals. The $23.6 million in costs associated with our crude oil activities include, in part, tank construction projects, a pipeline connection at one of our transloading facilities for the storage and handling of crude oil, a build-out project to increase the rail receipt and throughput storage capacities of primarily crude oil and converting certain storage tanks for the handling of crude oil at our Albany, New York terminal and miscellaneous upgrades. Certain of the $23.6 million in costs associated with our crude oil activities include expenditures related to our Beulah, North Dakota facility, 60% of which was funded by us and 40% was funded by the noncontrolling interest at Basin Transload. These costs are reported in the accompanying consolidated statement of cash flows as we concluded that we control the entity based on an evaluation of the outstanding voting interests.

        In 2012, expansion capital expenditures included acquisitions of approximately $294.5 million associated with the purchase of Alliance, a portion of which was funded through equity and a portion was funded with cash, and $6.3 million associated with the acquisition of six gasoline stations from Mutual Oil Company. In addition we had $31.7 million in non-acquisition related expansion capital expenditures. The $31.7 million consists of $13.5 million in costs primarily associated with our crude oil activities, $7.8 million in site expansion and improvements at certain retail gasoline stations and $6.7 million in costs associated with the building of a propane storage and distribution facility in Albany, New York, $1.7 million in costs related to information technology, including increases in storage and computing capacity, $0.5 million in costs to acquire land for future development and $1.5 million in other expansion capital expenditures. The $13.5 million in costs associated with our crude oil activities include a build-out project to increase the rail receipt and throughput storage capacities of primarily crude oil and converting certain storage tanks for the handling of crude oil at our Albany, New York terminal and tank construction costs at a transloading facility in North Dakota for the storage and handling of crude oil.

        In 2011, expansion capital expenditures included $3.4 million in costs associated with our crude oil activities, $1.8 million in costs related to propane tanks for future installation, $1.6 million in costs related to information technology, including increases in storage and computing capacity and hardware and software related to our branded gasoline business, $1.3 million in costs related to our Albany, New York terminal, $1.2 million in gasoline station equipment, $1.1 million in costs related to our three refined petroleum products terminals in Newburgh, New York, $0.6 million in bio-fuel conversion costs at our Providence, Rhode Island terminal, $0.6 million in costs at our Revere, Massachusetts terminal and $0.1 million in other expansion capital expenditures.

        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

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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.

    Cash Flow

 
  Year Ended December 31,  
 
  2013   2012   2011  
 
  (in thousands)
 

Net cash provided by (used in) operating activities

  $ 255,147   $ 232,452   $ (17,357 )

Net cash used in investing activities

  $ (243,207 ) $ (226,488 ) $ (13,369 )

Net cash (used in) provided by financing activities

  $ (8,700 ) $ (4,315 ) $ 32,693  

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

        Net cash provided by operating activities was $255.1 million for 2013 compared to $232.4 million for 2012, for a year-over-year increase in cash provided by operating activities of $22.7 million. Net cash provided by operating activities was $232.4 million for 2012 compared to net cash used in operating activities of $17.4 million for 2011, for a year-over-year increase in cash provided by operating activities of $249.8 million. The primary drivers of the changes for the years ended December 31 include the following (in thousands):

 
  2013   2012   Change   2012   2011   Change  

Decrease (increase) in accounts receivable

  $ 8,524   $ (57,160 ) $ 65,684   $ (57,160 ) $ (70,464 ) $ 13,304  

Decrease (increase) in inventories

  $ 61,992   $ 40,898   $ 21,094   $ 40,898   $ (77,313 ) $ 118,211  

Increase (decrease) in accounts payable

  $ 18,667   $ 146,947   $ (128,280 ) $ 146,947   $ 132,307   $ 14,640  

Decrease (increase) in the change in fair value of forward fixed price contracts

  $ 5,778   $ (9,845 ) $ 15,623   $ (9,845 ) $ (10,958 ) $ 1,113  

(Decrease) increase in accrued expenses and other current liabilities

  $ (3,065 ) $ 25,177   $ (28,242 ) $ 25,177   $ 3,999   $ 21,178  

        For 2013, including the beginning account balances related to Basin Transload and Cascade Kelly as of their respective acquisition dates (see Note 3 of Notes to Consolidated Financial Statements included elsewhere in this report), the decrease in accounts receivable was due to a decrease in refined petroleum prices year over year and the decrease in inventories was due to carrying lower levels of inventory. The increase in accounts payable was due primarily to an increase in our crude oil activities.

        In addition, through the use of regulated exchanges or derivatives, we maintain a position that is substantially hedged with respect to our inventories. Specifically, due to market direction, the contracts supporting our forward fixed price hedge program provided funds in 2013.

        For 2012, including the beginning account balances related to Alliance as of the acquisition date, we had an increase in the carrying value of accounts payable due to higher prices year over year and to the expansion of our crude oil activities. We also had an increase in the carrying value of accrued expenses and other current liabilities, offset by an increase in accounts receivable due to increased

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prices year over year and to the growth in our gasoline distribution business. The decrease in inventories was due to carrying lower levels of inventory. In addition, due to market direction, the contracts supporting our forward fixed price hedge program required margin payments in 2012.

        For 2011, we experienced increases in refined petroleum product and renewable fuel prices and, as a result, we funded additional working capital requirements. Primarily due to the rise in prices, we had increases in the carrying values in inventories, accounts receivable and accounts payable. In addition, due to market direction, the contracts supporting our forward fixed price hedge program required margin payments in 2011.

        Net cash used in investing activities was $243.2 million for 2013 and included $185.3 million related to our 2013 acquisitions ($91.1 million for our 60% membership interest in Basin Transload and $94.2 million for Cascade Kelly), $56.1 million in expansion capital expenditures and $11.0 million in maintenance capital expenditures, offset by $9.2 million in proceeds from the sale of property and equipment.

        Net cash used in investing activities was $226.4 million for 2012 and included $181.9 million and $6.8 million in cash used to fund the acquisitions of Alliance and of six gasoline stations from Mutual Oil Company, respectively, $31.7 million in expansion capital expenditures and $13.1 million in maintenance capital expenditures, offset by $7.1 million in proceeds from the sale of property and equipment.

        Net cash used in investing activities was $13.4 million for 2011 and included $4.2 million in maintenance capital expenditures and $11.7 million in expansion capital expenditures, offset by approximately $2.5 million in proceeds from the sale of property and equipment.

        See "—Capital Expenditures" for a discussion of our expansion capital expenditures for the years ended December 31, 2013, 2012 and 2011.

        Net cash used in financing activities was $8.7 million for 2013 and included $97.5 million in payments on our working capital revolving credit facility, $67.3 million in cash distributions to our common unitholders and our general partner, $4.6 million in the repurchase of common units pursuant to our repurchase program for future satisfaction of our general partner's obligations, $2.9 million in distributions to our noncontrolling interest and $2.1 million in repurchased units held for tax obligations related to units distributed under an LTIP award granted in 2009, offset by $147.9 million in proceeds from the issuances of our senior notes, $12.7 million in payments on our revolving credit facility, $3.7 million in our line of credit related to Basin Transload and $1.4 million capital contributions from our noncontrolling interest.

        Net cash used in financing activities was $4.3 million for 2012 and primarily included $164.4 million in payments on our working capital revolving credit facility, $54.7 million in cash distributions to our common unitholders and our general partner and $2.2 million in the repurchase of common units pursuant to our repurchase program for future satisfaction of our general partner's obligations, offset by $217.0 million in borrowings from our revolving credit facility.

        Net cash provided by financing activities was $32.7 million for 2011 and primarily included $102.2 million in borrowings from our working capital revolving credit facility and $69.6 million in net proceeds from our February 2011 public offering of common units, offset by $95.0 million in payments on our revolving credit facility, $42.8 million in cash distributions to our common and subordinated unitholders and our general partner, $0.7 million in repurchased units held for tax obligations related to units distributed under the LTIP, and $0.6 million in the repurchase of common units pursuant to our repurchase program for future satisfaction of our general partner's obligations. Our 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.

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    Credit Agreement

        On December 16, 2013, we entered into a second amended and restated credit agreement. Total commitments under our credit agreement are $1.625 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 April 30, 2018.

        As of December 31, 2013, there were two facilities under the 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 $1.0 billion; and

    a $625.0 million revolving credit facility to be used for acquisitions, joint ventures, capital expenditures, letters of credit 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 working capital revolving credit facility, the revolving credit facility, or both, by up to another $300.0 million, in the aggregate, for a total credit facility of up to $1.925 billion. Any such request for an increase by us must be in a minimum amount of $5.0 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 $1.625 billion.

        In addition, the credit agreement includes a swing line pursuant to which Bank of America, N.A., as the swing line lender, may make swing line loans in U.S. Dollars in an aggregate amount equal to the lesser of (a) $50.0 million and (b) the Aggregate WC Commitments (as defined in the credit agreement). Swing line loans will bear interest at the Base Rate (as defined in the credit agreement). The swing line is a sub-portion of the working capital revolving credit facility and is not an addition to the total available commitments of $1.625 billion.

        Borrowings under the credit agreement are available in U.S. Dollars and Canadian Dollars. The aggregate amount of loans made under the credit agreement denominated in Canadian Dollars cannot exceed $200.0 million.

        Availability under the 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, borrowings under the working capital revolving credit facility cannot exceed the then current borrowing base. Availability under the borrowing base may be affected by events beyond our control, such as changes in 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.

        Commencing December 16, 2013, borrowings under the working capital revolving credit facility bear interest at (1) the Eurocurrency rate plus 2.00% to 2.50%, (2) the cost of funds rate plus 2.00% to 2.50%, or (3) the base rate plus 1.00% to 1.50%, each depending on the Utilization Amount (as defined in the credit agreement). From November 16, 2012 through December 15, 2013, borrowings under the working capital revolving credit facility bore interest at (1) the Eurodollar rate plus 2.00% to 2.50%, (2) the cost of funds rate plus 2.00% to 2.50%, or (3) the base rate plus 1.00% to 1.50%, each depending on the Utilization Amount (as defined in the prior credit agreement). From January 1, 2011 through November 15, 2012, borrowings under the working capital revolving credit facility bore 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 prior credit agreement, which in turn depended upon the Utilization Amount (as defined in the prior credit agreement).

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        Commencing December 16, 2013, borrowings under the revolving credit facility bear interest at (1) the Eurocurrency rate plus 2.25% to 3.25%, (2) the cost of funds rate plus 2.25% to 3.25%, or (3) the base rate plus 1.25% to 2.25%, each depending on the Combined Total Leverage Ratio (as defined in the credit agreement). From November 16, 2012 through December 15, 2013, borrowings under the revolving credit facility bore interest at (1) the Eurodollar rate plus 2.50% to 3.50%, (2) the cost of funds rate plus 2.50% to 3.50%, or (3) the base rate plus 1.50% to 2.50%, each depending on the Combined Total Leverage Ratio (as defined in the prior credit agreement). From January 1, 2011 through November 15, 2012, borrowings under the revolving credit facility bore 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 prior credit agreement, which in turn depended upon the Combined Total Leverage Ratio (as defined in the prior credit agreement).

        The average interest rates for the Credit Agreement were 4.2%, 4.0% and 4.1% for the years ended December 31, 2013, 2012 and 2011, respectively.

        The credit agreement provides for a letter of credit fee equal to the then applicable working capital rate or then applicable revolver rate (each such rate as defined in the credit agreement) 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, ranging from 0.375% to 0.50% per annum.

        As of December 31, 2013, we had total borrowings outstanding under the credit agreement of $761.7 million, including $434.7 million outstanding on the revolving credit facility. In addition, we had outstanding letters of credit of $383.4 million. Subject to borrowing base limitations, the total remaining availability for borrowings and letters of credit was $479.9 million and $218.9 million at December 31, 2013 and 2012, respectively.

        Our obligations under the credit agreement are secured by substantially all of our assets and the assets of our wholly-owned subsidiaries.

        The credit agreement imposes financial covenants that require us to maintain certain minimum working capital amounts, 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, 2013. 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). In addition, the credit agreement limits distributions by us to our unitholders to the amount of Available Cash (as defined in the partnership agreement).

    8.00% Senior Notes

        On February 14, 2013, we entered into a Note Purchase Agreement (the "February Purchase Agreement") with FS Energy and Power Fund ("FS Energy"), with respect to the issue and sale by us to FS Energy of an aggregate principal amount of $70.0 million unsecured 8.00% Senior Notes due 2018 (the "8.00% Notes"). The 8.00% Notes were issued in a private placement exempt from registration under the Securities Act of 1933, as amended (the "Securities Act") and have not been registered under the Securities Act or any state securities laws, and may not be offered or sold except pursuant to an exemption from the registration requirements of the Securities Act and applicable state laws.

        Closing of the offering occurred on February 14, 2013. The 8.00% Notes were sold to FS Energy at 97% of their face amount, resulting in net proceeds to us of approximately $67.9 million. Additionally, we separately paid fees and offering expenses. The discount of $2.1 million at issuance will be accreted as additional interest over the expected term on the 8.00% Notes. On February 15, 2013, we used the net proceeds from the offering, after paying fees and offering expenses, to finance a

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portion of our acquisition of all of the outstanding membership interests in Cascade Kelly and to pay related transaction costs.

        The 8.00% Notes were issued pursuant to an indenture dated as of February 14, 2013 (as amended or supplemented, the "February Indenture") among us, our subsidiary guarantors and FS Energy. The 8.00% Notes will mature on February 14, 2018. Interest on the 8.00% Notes accrued from February 14, 2013 and is paid semi-annually on February 14 and August 14 of each year, beginning on August 14, 2013. We may redeem all or some of the 8.00% Notes at any time or from time to time pursuant to the terms of the February Indenture. The 8.00% Notes are also subject to optional or mandatory exchange for HY Bonds (as such term is defined in the February Indenture) at the time and on the terms specified in the February Indenture. The holders of the 8.00% Notes may require us to repurchase the 8.00% Notes following certain asset sales or a Change of Control (as defined in the February Indenture) at the prices and on the terms specified in the February Indenture.

        On December 20, 2013, we, our subsidiary guarantors and FS Energy entered into a Second Supplemental Indenture, which is supplemental to the February Indenture (the "Second Supplemental Indenture"). The Second Supplemental Indenture (i) adds Global CNG LLC as a guarantor, (ii) increases the amount of Equity Interests (as defined in the February Indenture) of us or any Restricted Subsidiary (as defined in the February Indenture) of us that we and the Restricted Subsidiaries may purchase, redeem or otherwise acquire in any calendar year from $5.0 million to $10.0 million, and (iii) allows us and our Restricted Subsidiaries to incur Indebtedness (as defined in the February Indenture) represented by Capital Lease Obligations (as defined in the February Indenture), mortgage financings or purchase money obligations incurred to finance construction or improvement of property, plant or equipment, up to the greater of $60.0 million or 5.5% of our Consolidated Net Tangible Assets (as defined in the February Indenture).

        The 8.00% Notes are guaranteed on a senior, unsecured basis by certain of our wholly-owned subsidiaries. The February Indenture contains covenants that are no more restrictive to us in the aggregate than the terms, conditions, covenants and defaults contained in our credit agreement and will limit our ability to, among other things, incur additional indebtedness, make distributions to equity owners, make certain investments, restrict distributions by our subsidiaries, create liens, enter into sale-leaseback transactions, sell assets or merge with other entities.

    7.75% Senior Notes

        On December 23, 2013, we entered into a Note Purchase Agreement (the "December Purchase Agreement") with FS Energy and Power Fund, KARBO, L.P., Kayne Anderson Capital Income Partners (QP), L.P., Kayne Anderson Income Partners, L.P., Kayne Anderson Infrastructure Income Fund, L.P., Kayne Anderson Non-Traditional Investments, L.P., KANTI (QP), L.P. and Kayne Energy Credit Opportunities, L.P. as purchasers (the "Purchasers"), with respect to the issue and sale by us to the Purchasers of an aggregate principal amount of $80.0 million unsecured 7.75% Senior Notes due 2018 (the "7.75% Notes"). The 7.75% Notes were issued in a private placement exempt from registration under the Securities Act and have not been registered under the Securities Act or any state securities laws, and may not be offered or sold except pursuant to an exemption from the registration requirements of the Securities Act and applicable state laws.

        Closing of the offering occurred on December 23, 2013. The 7.75% Notes were sold to the Purchasers at their face amount, resulting in proceeds to us of $80.0 million. Additionally, we separately paid fees and offering expenses. We used a portion of the net proceeds from the offering to pay outstanding indebtedness and for general partnership purposes.

        The 7.75% Notes were issued pursuant to an indenture dated as of December 23, 2013 (the "December Indenture") among us, our subsidiary guarantors and the Purchasers. The 7.75% Notes will mature on December 23, 2018. Interest on the 7.75% Notes accrued from December 23, 2013. Interest

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will be paid on the 7.75% Notes semi-annually on December 23 and June 23 of each year, beginning on June 23, 2014.

        We may redeem all or some of the 7.75% Notes at any time or from time to time pursuant to the terms of the December Indenture. The 7.75% Notes are also subject to optional or mandatory exchange for HY Bonds (as such term is defined in the December Indenture) at the time and on the terms specified in the December Indenture. The holders of the 7.75% Notes may require us to repurchase the 7.75% Notes following certain asset sales or a Change of Control (as defined in the December Indenture) at the prices and on the terms specified in the December Indenture.

        The 7.75% Notes are guaranteed on a senior, unsecured basis by certain of our wholly-owned subsidiaries. The December Indenture contains covenants that are no more restrictive to us in the aggregate than the terms, conditions, covenants and defaults contained in our credit agreement and will limit our ability to, among other things, incur additional indebtedness, make distributions to equity owners, make certain investments, restrict distributions by our subsidiaries, create liens, enter into sale-leaseback transactions, sell assets or merge with other entities.

    Line of Credit

        On December 9, 2013, Basin Transload LLC entered into a line of credit facility which allows for borrowings by Basin Transload LLC of up to $10.0 million on a revolving basis. The facility matures on December 9, 2014 and had an outstanding balance of $3.7 million at December 31, 2013. The facility is secured by substantially all of the assets of Basin Transload LLC and is not guaranteed by us or any of our wholly-owned subsidiaries.

    Deferred Financing Fees

        We incur bank fees related to our credit agreement and other financing agreements. These deferred financing fees are amortized over the life of the credit agreement or senior notes. We capitalized deferred financing fees of $17.7 million, $5.3 million and $2.3 million for the years ended December 31, 2013, 2012 and 2011, respectively. Amortization expense of approximately $6.9 million, $5.8 million and $4.7 million for the years ended December 31, 2013, 2012 and 2011, respectively, are included in interest expense in the accompanying consolidated statements of income. Unamortized fees are included in other current assets and other long-term assets.

    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, 2013, 2012 and 2011.

Environmental Matters

        Our business of supplying refined petroleum products, renewable fuels, crude oil and propane 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." For additional information regarding our environmental liabilities, see Note 9 of Notes to Consolidated Financial Statements included elsewhere in this report.

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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 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:

    Inventory

        Except for our convenience store inventory and our RIN inventory, we hedge substantially all of our inventory, primarily through futures contracts. These futures contracts are entered into when inventory is purchased and are designated as fair value hedges against the inventory on a specific barrel basis. 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, we have convenience store inventory and RIN inventory which are carried at the lower of historical cost or market. Inventory from Cascade Kelly was nominal at December 31, 2013 and is carried at the lower of cost or market.

        In addition to our own inventory, we have exchange agreements for petroleum products with unrelated third party suppliers, whereby we may draw inventory from these other suppliers and suppliers may draw inventory from us. Positive exchange balances are accounted for as accounts receivable. Negative exchange balances are accounted for as accounts payable. Exchange transactions are valued using current carrying costs.

    Leases

        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 lease agreements with the Port of St. Helens for land and for access rights to a rail spur and dock located at the our Oregon facility. We also have entered into terminal and throughput lease arrangements with various unrelated oil terminals and third parties, certain of which arrangements have minimum usage requirements. Please read Items 1 and 2, "Business and Properties—Storage." In addition, we lease certain gasoline stations from third parties under long-term arrangements with various expiration dates. We have a long-term lease agreement with Getty Realty which enables us to supply and operate certain Getty Realty gasoline station sites. The initial lease term for the locations is 15 years and includes multiple five-year renewal options. In addition, we lease railcars pursuant to various lease 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 gasoline stations and lease income from space leased to several unrelated third parties at several 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

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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.

    Revenue Recognition

        Sales relate primarily to the sale of refined petroleum products, renewable fuels, crude oil, natural gas and propane and are recognized along with the related receivable upon delivery, net of applicable provisions for discounts and allowances. We may also provide for shipping costs at the time of sale, which are included in cost of sales. In addition, we generate revenue from our logistics activities. The amounts recorded for bad debts are generally based upon a specific analysis of aged accounts 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. We also recognize convenience store sales of gasoline, grocery and other merchandise and commissions on lottery at the time of the sale to the customer. Gasoline station 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, renewable fuels and crude oil 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.

        We collect trustee taxes, which consist of various pass through taxes collected from customers on behalf of taxing authorities, and remits such taxes directly to those taxing authorities. As such, it is our policy to exclude trustee taxes from revenues and cost of sales and account for them as current liabilities.

    Derivative Financial Instruments

        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. We principally uses derivative instruments to hedge the commodity risk associated with our inventory and product purchases and sales and to hedge variable interest rates associated with our credit facilities.

        Fair Value Hedges—We enter into futures contracts in the normal course of business to the reduce risk of loss of inventory value, which could result from fluctuations in market prices. These futures contracts are designated as fair value hedges against the inventory with specific futures contracts matched to specific barrels of inventory. As a result of our hedge designation on these transactions, the futures contracts are recorded on our consolidated balance sheet and marked to market through the use of independent markets based on the prevailing market prices of such instruments at the date of valuation. Likewise, the underlying inventory being hedged is also marked to market. Changes in the fair value of the futures contracts, as well as the change in the fair value of the hedged inventory, are recognized in the consolidated statement of income through cost of sales. These futures contracts are settled on a daily basis by us through brokerage margin accounts.

        Cash Flow Hedges—We utilize various interest rate derivative instruments to hedge variable interest rate on our debt. These derivative instruments are designated as cash flow hedges of the underlying debt. 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 (loss) and reclassified into interest expense or interest income in the same period during which the hedged transaction affects earnings.

        In September 2008, we executed a zero premium interest rate collar with a major financial institution. The collar, which became effective on October 2, 2008 and expired on October 2, 2013, was

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used to hedge the variability in cash flows in monthly interest payments made on $100.0 million of one-month LIBOR-based borrowings on the credit facility (and subsequent refinancings thereof) due to changes in the one-month LIBOR rate.

        In October 2009, we executed an interest rate swap with a major financial institution. The swap, which became effective on May 16, 2011 and expires on May 16, 2016, is 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 on the credit facility at a fixed rate of 3.93%.

        In April 2011, we executed an interest rate cap with a major financial institution. The rate cap, which became effective on April 13, 2011 and expires on April 13, 2016, is used to hedge the variability in interest payments due to changes in the one-month LIBOR rate above 5.5% with respect to $100.0 million of one-month LIBOR-based borrowings on the credit facility.

        In September 2013, we executed an interest rate swap with a major financial institution. The swap, which became effective on October 2, 2013 and expires on October 2, 2018, is used to hedge the variability in cash flows in monthly interest payments due to changes in the one-month LIBOR swap curve with respect to $100.0 million of one-month LIBOR-based borrowings on the credit facility at a fixed rate of 1.819%. This swap essentially replaced the interest rate collar that expired on October 2, 2013.

        Other Derivative Activity—We use futures contracts, and occasionally swap agreements, to hedge our commodity exposure under forward fixed price purchase and sale commitments on our products. These derivatives are not designated by us as either fair value hedges or cash flow hedges. Rather, the forward fixed price purchase and sales commitments, which meet the definition of a derivative, are reflected in our consolidated balance sheet. The related futures contracts (and swaps, if applicable) are also reflected in our consolidated balance sheet, thereby creating an economic hedge. Changes in the fair value of the futures contracts (and swaps, if applicable), as well as offsetting gains or losses due to the change in the fair value of forward fixed price purchase and sale commitments, are recognized in the consolidated statement of income through cost of sales. These futures contracts are settled on a daily basis by us through brokerage margin accounts.

        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 other logistical issues inherent in the business, such as weather conditions. In connection with managing these positions, maintaining a constant presence in the marketplace, and managing the futures market outlook for future anticipated inventories, which are necessary for our business, we engage in a controlled trading program for up to an aggregate of 250,000 barrels of products at any one point in time. Any derivatives not involved in a direct hedging activity are marked to market and recognized in the consolidated statement of income through cost of sales.

        We also market and sell natural gas by entering into forward purchase commitments for natural gas when we enter into arrangements for the forward sale commitment of product for physical delivery to third-party users. We reflect the fair value of forward fixed purchase and sales commitments in our consolidated balance sheet. Changes in the fair value of the forward fixed price purchase and sale commitments are recognized in the consolidated statement of income through cost of sales.

        During the years ended December 31, 2013 and 2012, we entered into forward currency contracts to hedge certain foreign denominated (Canadian) product purchases. These forward contracts are not designated and are reflected in the consolidated balance sheet. Changes in the fair values of these forward currency contracts are reflected in cost of sales.

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    Valuation of Intangibles and Other Long-Lived Assets

        Our long-lived assets include property and equipment and intangible 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. Accordingly, we evaluate for impairment whenever indicators of impairment are identified. 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 indicators of impairment are present, we assess impairment by comparing the undiscounted projected future cash flows from the long-lived assets to their carrying value. If the undiscounted cash flows are less than the carrying value, the long-lived assets will be reduced to their fair value. 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.

    Goodwill

        Goodwill represents the future economic benefits arising from assets acquired in a business combination that are not individually identified and separately recognized. A portion of our goodwill is allocated to the Wholesale reporting unit, and a portion of the goodwill is allocated to the Gasoline Distribution and Station Operations reporting unit. Goodwill is tested for impairment annually as of October 1 or when events or changes in circumstances indicate that the carrying amount of goodwill may not be recoverable. The impairment test first includes a qualitative assessment in order to conclude if it is more likely than not that the reporting unit's fair value exceeds its carrying value. If necessary, we would then complete a two-step quantitative assessment.

        Factors included in the quantitative assessment include both macro-economic conditions and industry specific conditions. For the quantitative assessment, the reporting unit's fair value is estimated using a weighted average of discounted cash flow approach and market comparables approach. In the quantitative assessment, we compare the fair value of the reporting unit to its carrying value. If the fair value of the reporting unit exceeds the carrying value, goodwill is not impaired and no further testing is required. If the carrying value exceeds the fair value, then the second step must be performed to determine the implied fair value of the reporting unit. If the carrying value exceeds the implied fair value then we would record an impairment loss equal to the difference.

    Environmental and Other Liabilities

        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 all related contingencies are resolved, generally upon cash receipt.

        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 and 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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    Related Party Transactions

        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 currently utilize interest rate swaps and an interest rate cap to manage exposure to interest rate risk and various derivative instruments to manage exposure to commodity risk.

    Interest Rate 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, swaps and caps to hedge interest obligations on specific and anticipated debt issuances.

        As of December 31, 2013, we had total borrowings outstanding under the credit agreement of $761.7 million. Please read Item 7, "Management's Discussion and Analysis—Liquidity and Capital Resources—Credit Agreement" for information on interest rates related to our borrowings. 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 $7.6 million annually, assuming, however, that our indebtedness remained constant throughout the year.

        In September 2008, we executed a zero premium interest rate collar with a major financial institution. The collar, which became effective on October 2, 2008 and expired on October 2, 2013, was used to hedge the variability in cash flows in monthly interest payments made on $100.0 million of one-month LIBOR-based borrowings on the credit facility (and subsequent refinancings thereof) due to changes in the one-month LIBOR rate.

        In October 2009, we executed an interest rate swap with a major financial institution. The swap, which became effective on May 16, 2011 and expires on May 16, 2016, is 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 on the credit facility at a fixed rate of 3.93%.

        In April 2011, we executed an interest rate cap with a major financial institution. The rate cap, which became effective on April 13, 2011 and expires on April 13, 2016, is used to hedge the variability in interest payments due to changes in the one-month LIBOR rate above 5.5% with respect to $100.0 million of one-month LIBOR-based borrowings on the credit facility.

        In September 2013, we executed a forward interest rate swap with a major financial institution. The swap, which became effective on October 2, 2013 and expires on October 2, 2018, is used to hedge the variability in cash flows in monthly interest payments due to changes in the one-month LIBOR swap curve with respect to $100.0 million of one-month LIBOR-based borrowings on the credit facility at a fixed rate of 1.819%. This swap essentially replaced the interest rate collar which expired on October 2, 2013.

        See Notes 2 and 4 of Notes to Consolidated Financial Statements for additional information on our derivative instruments.

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    Commodity Risk

        We hedge our exposure to price fluctuations with respect to refined petroleum products, renewable fuels, crude oil and gasoline blendstocks in storage and expected purchases and sales of these commodities. The derivative instruments utilized consist primarily of futures contracts traded on the NYMEX, CME and ICE 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, as well as inherent basis risk, exposure to 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 other logistical issues inherent in the business, such as weather conditions. In connection with managing these positions, maintaining a constant presence in the marketplace and managing the futures market outlook for future anticipated inventories, which are necessary for our business, we engage in a controlled trading program for up to an aggregate of 250,000 barrels of products at any one point in time. Any derivatives not involved in a direct hedging activity are marked to market and recognized in the consolidated statement of income through cost of sales. In addition, because a portion of our crude oil business is conducted in Canadian dollars, we may use foreign currency derivatives to minimize the risks of unfavorable exchange rates. These instruments include foreign currency exchange contracts and forwards. In conjunction with entering into the commodity derivative, we may enter into a foreign currency derivative to hedge the resulting foreign currency risk. These foreign currency derivatives are generally short-term in nature and not designated for hedge accounting.

        We utilize futures contracts and other derivative instruments to minimize or hedge the impact of commodity price changes on our inventories and forward fixed price commitments. Any hedge ineffectiveness is reflected in our results of operations. We utilize regulated exchanges, including the NYMEX, CME and ICE, which are regulated exchanges for the commodities that each 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 such as ethanol, 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.

        At December 31, 2013, 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 at
December 31,
2013
  Effect of 10%
Price Increase
  Effect of 10%
Price Decrease
 

Futures contracts

  $ (24,568 ) $ (31,710 ) $ 31,710  

Swaps, options and other, net

    8     (3,555 )   1,465  
               

  $ (24,560 ) $ (35,265 ) $ 33,175  
               
               

        The fair values of the futures contracts are based on quoted market prices obtained from the NYMEX and the CME. The fair value of the swaps and option contracts are estimated based on

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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, 2013. 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 physical 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 brokers 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 $21.8 million at December 31, 2013.

        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 three clearing brokers, all major financial institutions, 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.

    Disclosure 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 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 this evaluation, management concluded as of December 31, 2013 that our disclosure controls and procedures were not effective at the reasonable assurance level due to material weaknesses in our internal control over financial reporting as described in Management's Annual Report on Internal Control over Financial Reporting below.

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    Internal Control Over Financial Reporting

    Management's Annual Report

        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 (1992 framework). Based on that evaluation, we identified material weaknesses in the design and operating effectiveness of our internal control over financial reporting. A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis. Specifically, we were not performing timely and comprehensive reconciliations between our renewable identification numbers ("RIN") on hand and our renewable volume obligation ("RVO"). Additionally, the integration and communication between our departments were not effective in identifying forward RIN purchase and sales contracts which were unfavorable. In addition, due to the inability to age and analyze the lag associated with certain accrued liabilities related to petroleum products, there was a design deficiency in the precision of our monitoring control over these liabilities. We also identified other deficiencies, which when aggregated, represent a material weakness in our financial statement close process. These control deficiencies contributed to material errors in previously issued 2013 interim financial statements. As a result of these material weaknesses, we have concluded that we did not maintain effective internal control over financial reporting as of December 31, 2013.

        The effectiveness of internal control over financial reporting was audited by Ernst & Young, an independent registered public accounting firm, as stated in their report included elsewhere herein.

    Changes in Internal Control

        Except for the material weaknesses noted above, there has not been any change in our internal control over financial reporting that occurred during the quarter ended December 31, 2013 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

    Remediation of Material Weakness in Internal Control over Financial Reporting

        In response to management's determination as of the date of this filing, we have designed and substantially implemented the following changes in our internal control over financial reporting:

    Enhanced integration of and communication among the fuel compliance officer, the operational groups and the finance and accounting personnel.

    Established a timely and comprehensive reconciliation of compliance data used in conjunction with the EPA systems and data used in the financial reporting process.

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    Established a RIN operational policy and monitor compliance with and effectiveness of that policy through the risk department reporting to senior management.

    Developed reporting systems to monitor RIN positions and compliance with the RIN operational policy that will be reconciled to the accounting records and the EPA Moderated Transaction System (EMTS).

    Established policies and procedures with respect to accrued cost of goods sold liabilities to assess a timeframe as to when to investigate aged accruals to determine if they are still needed and designate personnel to monitor compliance with same.

    Enhanced computer system functionality to allow for the review of accrued items for age and activity in accordance with established policy.

    Hired additional experienced employees in the finance and accounting function.

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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, 2013, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 framework) (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 Partnership's internal control over financial reporting based on our audit.

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

        A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Partnership; (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 Partnership; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Partnership'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.

        A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the partnership's annual or interim financial statements will not be prevented or detected on a timely basis. Management has identified material weaknesses in controls principally related to renewable identification numbers ("RINs"), certain accrued liabilities related to the procurement of petroleum products and other deficiencies, which when aggregated, represent a material weakness in the Partnership's financial statement close process.

        We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the 2013 consolidated financial statements as of December 31, 2013 and 2012 and the related consolidated statements of income, comprehensive income, partners' equity and cash flows for each of the three years in the period ended December 31, 2013. These material weaknesses were considered in determining the nature, timing and extent of audit tests applied in our audit of the 2013 consolidated financial statements, and this report does not affect our report dated March 31, 2014, which expressed an unqualified opinion on those financial statements.

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        In our opinion, because of the effect of the material weaknesses described above on the achievement of the objectives of the control criteria, Global Partners LP has not maintained effective internal control over financial reporting as of December 31, 2013, based on the COSO criteria.

                        /s/ ERNST & YOUNG LLP  

Boston, Massachusetts
March 31, 2014

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 Richard Slifka and the estate of Alfred A. Slifka directly and through their beneficial ownership of entities that own ownership interests in our general partner. Eric Slifka and Andrew Slifka beneficially own interests 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.

        Alfred A. Slifka, former chairman of the board of our general partner, passed away on March 9, 2014. Mr. Slifka's brother, Richard Slifka, succeeded him as chairman of the board of our general partner. Mr. Slifka's estate is in probate and his beneficially owned interests in Global Partners LP and its affiliates have not yet been settled.

        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 the sole 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.

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        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. Please read Item 13, "Certain Relationships and Related Transactions, and Director Independence—Relationship of Management with Global Petroleum Corp., AE Holdings Corp. and Alliance Energy LLC." Our non-management directors devote as much time as is necessary to prepare for and attend board of directors and committee meetings.

        Set forth below are the names, ages (as of March 28, 2014) and titles of persons currently serving as directors and executive officers of our general partner.

Name
  Age   Position with Global GP LLC

Richard Slifka

    73   Chairman

Eric Slifka

    48   President, Chief Executive Officer and Director

Andrew Slifka

    45   Executive Vice President and Director

Mark Romaine

    45   Chief Operating Officer

Daphne H. Foster

    56   Chief Financial Officer

Edward J. Faneuil

    61   Executive Vice President, General Counsel and Secretary

Charles A. Rudinsky

    66   Executive Vice President and Chief Accounting Officer

David K. McKown

    76   Director

Robert J. McCool

    75   Director

Kenneth I. Watchmaker

    71   Director

        Richard Slifka was elected Vice Chairman of the Board of our general partner in March 2005 and became chairman in March 2014. He had 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 serves as Vice Chairman of the board of directors of AE Holdings Corp., a privately held affiliated company. 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 and Independent Fuel Terminal Operators Association. 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 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 AE Holdings Corp., a privately held affiliated company. He serves on the board of directors of the New York Oil Heat Association, National Oilheat Research Alliance, New England Fuel Institute, Energy Policy Research Foundation, Inc., Massachusetts Youth Committed to Winning and Massachusetts General Hospital President's Council. 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.

        Andrew Slifka was elected to serve as a director of our general partner in April 2012. He has served as Executive Vice President of our general partner since March 2012 and as President of

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Alliance Energy LLC and its predecessor, Alliance Energy Corp., since November 2007. He has been employed with Alliance Energy LLC since 1999. Mr. Slifka served as Vice President and General Manager for the Northeast region (Rhode Island, Massachusetts, New Hampshire and Maine) of Alliance Energy Corp. from 1999 to 2003 and as Executive Vice President from 2003 to November 2007. From 1991 to 1999, Mr. Slifka held various positions in the supply, distribution and marketing departments with the predecessor of Global Companies LLC, Global Petroleum Corp. He serves on the boards of directors of Independent Oil Marketers Association and CF&MS Fund Foundation. Mr. Slifka is the son of Richard Slifka and the nephew of Alfred A. Slifka.

        Mark Romaine was elected Chief Operating Officer of our general partner and has served in that office since July 2013. Mr. Romaine served as Senior Vice President of Light Oil Supply and Distribution from 2006 until June 2013. He joined a predecessor company in 1998 as Premium Fuels Marketing Manager. Mr. Romaine's experience in the petroleum products industry includes operations and marketing positions with Volta Oil in Plymouth, Massachusetts. Mr. Romaine received a bachelor's degree from Providence College and an MBA from the University of Massachusetts.

        Daphne H. Foster was elected Chief Financial Officer of our general partner partner and has served in that office since July 2013. Ms. Foster served as Treasurer of our general partner from 2010 through June 2013. She joined Global in 2007. Her experience in the petroleum products industry includes several years as a Vice President in the Energy and Utilities Division of Bank of Boston. Ms. Foster started her banking career in 1982 at Bank of Boston and later joined Citizens Financial Group, where she oversaw the Loan Officer Development Program. Ms. Foster received a bachelor's degree and an MBA from Boston University.

        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 the Independent Oil Marketers Association.

        Charles A. Rudinsky was elected Senior Vice President and Chief Accounting Officer of our general partner in March 2005 and was named Executive Vice President and Treasurer in February 2007. Mr. Rudinsky continues to serve as Chief Accounting Officer and Co-Director of Mergers & Acquisitions. 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 the Bank Loan Fund of 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 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 serves as a director of Safety Insurance Group, Newcastle Investment Co. and several private companies. Mr. McKown previously served as a member of the

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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. 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, 2013, 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), except for four Form 4 filings with respect to phantom units awarded to Messrs. Eric Slifka, Thomas J. Hollister, Edward J. Faneuil and Charles A. Rudinsky which were filed on July 1, 2013 and one Form 4 with respect to phantom units awarded by our general partner filed on September 20, 2013. Each of the four Form 4 filings on July 1, 2013 related to three transactions not reported on a timely basis. The Form 4 filed on September 20, 2013 related to two transactions that were not reported on a timely basis

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

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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.

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 2013.

        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, except for our gasoline station and convenience store employees and certain union personnel, who are employed by Global Montello Group Corp. ("GMG"). 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. 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 executive officers of our general partner. Executive officers of our general partner receive compensation in the form of base salaries, short-term incentive awards (contractual and/or discretionary) and long-term incentive awards. They are also 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 wholly-owned subsidiaries. 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, who prior to his retirement on June 30, 2013 served as our Chief Financial Officer ("CFO") and Chief Operating Officer ("COO"), Ms. Daphne H. Foster, who effective July 1, 2013 became our CFO, Mr. Mark A. Romaine, who effective July 1, 2013 became our COO, and the three most highly compensated executive officers of our general partner other than our CEO, CFOs and COOs during 2013, who were Mr. Andrew Slifka, our Executive Vice President and President of our Alliance Gasoline Division, Mr. Charles A. Rudinsky, our Executive Vice President and Chief Accounting Officer, and Mr. Edward J. Faneuil, our Executive Vice President and General Counsel. Each of Messrs. Eric Slifka, Andrew Slifka, and Faneuil has an employment agreement with our general partner. Mr. Rudinsky, Ms. Foster and Mr. Romaine are employees at will and do not have employment agreements with our general partner. Prior to his retirement, Mr. Hollister also had an employment agreement with our general partner.

        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 three of our named executive officers.

Compensation Objectives

        The objectives of our compensation program with respect to our named 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 named executive officer with a competitive total compensation program. We currently utilize the following compensation components:

    Base 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 and/or performance-based cash 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 compensation consultants to study and supply market compensation data and to assist our management and the Compensation Committee in formulating

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competitive compensation plans and arrangements. The Compensation Committee retained BDO USA, LLP ("BDO") as an outside compensation consultant during 2013.

        Under our executive compensation structure, our goal is for our named executive officers' total compensation to fall between the median (50th percentile) and 75th percentile of competitive total compensation levels, as identified by our compensation consultant's benchmarking results, 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 Executive Vice President and General Counsel is responsible for all of our environmental compliance functions, many of our human resources matters, many of our operational activities as determined by our CEO and many of our business transactions that he manages in an executive as well as a 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 in connection with our acquisition due diligence; and

    Our Executive Vice President who also serves as President of our Alliance Gasoline Division has executive responsibilities as well as primary oversight of our gasoline and convenience store business.

        During 2013, BDO worked with the Compensation Committee to revisit earlier benchmarking criteria and update them to better reflect a peer group of companies consistent with the size and scope of our business as it transformed during 2012, with our expanded product lines, increased focus on transportation logistics and growth in our gasoline station and convenience store business. In connection with this evaluation, BDO updated competitive pay level analyses for our named executive officers and analyzed competitive compensation levels for independent members of our general partner's board of directors for use during 2013 and future years. Analyses regarding competitive pay practices for named executive officers were updated based on information contained in proxies filed by several groups of companies with various characteristics comparable and relevant to our current size and scope of operations, including: 227 companies with comparable market capitalization and employees; 131 companies with comparable market capitalization and total assets; 32 oil and gas distribution and storage companies; 11 additional companies with comparable market capitalization, assets and related business operations; and nine companies in related businesses. Competitive methods and levels of compensation for non-employee members of our general partner's board of directors were analyzed using the proxy filings from the same external groups of companies described above.

        In addition, BDO worked with the Compensation Committee in 2013 to update the performance targets and associated levels of payouts contained in our 2013 short-term incentive plan for our named executive officers. Plan modifications were made to incorporate the increased scope of our operations and to ensure the plan is fully aligned with and consistent with our efforts to achieve critical business objectives. A complete description of changes made to the short-term incentive plan is included in the next section,—Elements of Compensation.

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. As described above, our goal is to target total compensation levels (i.e., base 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

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perform above or below our performance goals, we expect that result will be reflected in our compensation levels.

        The elements of the 2013 executive officer compensation of our general partner were base salaries, short-term incentive awards, discretionary bonuses, long-term equity incentive awards, retirement, deferred compensation 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:

Base Salaries

        Each named executive officer's base salary is a fixed component of compensation for each year. Base salary is designed to compensate executives for the responsibility of the level of the position they hold and sustained individual performance (including experience, scope of responsibility, results achieved and future potential). The base salaries for four of our named executive officers are set by the terms of their respective employment agreements; the base salaries for the named executive officers without employment agreements are set in accordance with our CEO's recommendations, using salary range information from BDO, and as approved by the Compensation Committee. Base salaries for Messrs. Eric Slifka, Andrew Slifka, Thomas Hollister, Edward Faneuil and Charles Rudinsky did not change in 2013. Base salaries for Ms. Daphne Foster and Mr. Mark Romaine, who were appointed CFO and COO, respectively, effective July 1, 2013 were established for their new roles at the time of their appointment. The base salaries in effect as of the end of 2013 for our named executive officers were as follows: $800,000 for Mr. Eric Slifka, $425,000 for Mr. Andrew Slifka; $578,000 for Mr. Hollister; $300,000 for Ms. Foster; $500,000 for Mr. Romaine; $376,000 for Mr. Faneuil; and $273,000 for Mr. Rudinsky.

Short-Term Incentive Awards—Contractual

        Thomas Hollister, our former COO and CFO, was entitled to an annual contractual bonus under his employment agreement with our general partner for each year in which he was employed by our general partner for the full year, based upon our achievement of specific targets established by the Compensation Committee. Mr. Hollister retired on June 30, 2013 and therefore was not entitled to a short-term contractual bonus under his employment agreement for 2013. Mr. Hollister waived the contractual bonuses under his employment agreement with our general partner for 2012 and 2011.

Short-Term Incentive Plans

        Our general partner established a cash bonus pool for 2013 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 2013 (the "STIP") included a performance-based component, for which 50% of the cash bonus pool was available (the "STIP Performance Component"), and a discretionary component, for which the other 50% 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 the Compensation Committee in March 2013 (the "DCF objective"). 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 ("DCF"). DCF is discussed under "Results of Operations—Evaluating Our Results of Operations" and reconciled to its most directly comparable GAAP financial measures under "Results of Operations—Key Performance Indicators" in Item 7, "Management's Discussion and Analysis of Financial Conditions and Results of Operations."

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        Under the STIP, each of our named executive officers was assigned an incentive target value expressed as a percentage of his base salary. The 2013 incentive target values were: 100% (or $800,000) for Mr. Eric Slifka; 93% (or $350,000) for Mr. Faneuil; 47% (or $200,000) for Mr. Andrew Slifka; and 41% (or $112,500) for Mr. Rudinsky. At the time of their appointments, incentive targets were established for Ms. Foster and Mr. Romaine at 67% (or $200,000) and 100% (or $500,000) respectively. Our former CFO and COO, Mr. Hollister, did not participate in the 2013 STIP. 50% of the target values for each named executive officer was allocated to his or her STIP Performance Component and 50% was allocated to his or her STIP Discretionary Component.

        STIP Performance Component (50% of the incentive target value):    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, a reduced payout under the STIP Performance Component when the DCF objective is not achieved, and no payout if the STIP Performance Component minimum threshold 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. We failed to achieve the minimum level of DCF to qualify for any incentive under the STIP Performance Component DCF objectives set by the Compensation Committee for 2013.

        STIP Discretionary Component (50% of the incentive target value):    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 than 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 us and, as may be applicable, the contributions of any or all of the named executive officers. The Compensation Committee awarded a range of 100 to 117% of the STIP Discretionary Component for 2013 as follows: 100% (or $400,000) for Mr. Eric Slifka; 100% (or $100,000) for Mr. Andrew Slifka; 100% (or $175,000) for Mr. Faneuil; 117% (or $66,000) for Mr. Rudinsky; 100% (or $100,000) for Ms. Foster; and 100% (or $250,000) for Mr. Romaine.

        In awarding the 2013 STIP Discretionary Component, the Compensation Committee recognized that the following strategic initiatives and opportunities, undertaken by us under the leadership of Mr. Slifka and executed by our named executive officers, transformed us beyond our historic businesses and provided us with vital growth opportunities. These strategic initiatives and opportunities include:

    We completed the acquisition of a 60% membership interest in Basin Transload, LLC, which operates two transloading facilities in Columbus and Beulah, North Dakota for crude oil and other products, with a combined rail loading capacity of 160,000 barrels per day (the "Basin acquisition").

    We completed the acquisition of 100% of the membership interests in Cascade Kelly Holdings LLC, which owns an ethanol plant and rail facilities for the transportation of ethanol and crude oil in Clatskanie, Oregon (the "CPBR acquisition").

        The Basin acquisition and the CPBR acquisition, together with the our existing terminal and rail facilities in Albany, New York, provide the foundation for our "virtual pipeline" to transport crude oil from the Bakken region in the Midwest to the east and west coasts of the United States. These acquisitions also build upon our logistics expertise in transporting petroleum products to supply our needs, and the expansion of the services being provided by us to third parties.

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        Each of our named executive officers other than Mr. Hollister, who retired on June 30, 2013, earned a short-term incentive award for 2013. A summary of these awards appears in the table below:

Name
    Target
Value as a %
of Salary
  Target
Value
($)
  2013 Award
Value as a %
of Target
Value
  2013 Award
Payouts
($)
 

Eric Slifka

  Total Award     100%     800,000     50%     400,000  

  Performance     50%     400,000          

  Discretionary     50%     400,000     100%     400,000  

Mark A. Romaine

 

Total Award

   
100%
   
500,000
   
50%
   
250,000
 

  Performance     50%     250,000          

  Discretionary     50%     250,000     100%     250,000  

Edward J. Faneuil

 

Total Award

   
93%
   
350,000
   
50%
   
175,000
 

  Performance     46.5%     175,000          

  Discretionary     46.5%     175,000     100%     175,000  

Andrew P. Slifka

 

Total Award

   
47%
   
200,000
   
50%
   
100,000
 

  Performance     23.5%     100,000          

  Discretionary     23.5%     100,000     100%     100,000  

Daphne H. Foster

 

Total Award

   
67%
   
200,000
   
50%
   
100,000
 

  Performance     33.5%     100,000          

  Discretionary     33.5%     100,000     100%     100,000  

Charles A. Rudinsky

 

Total Award

   
41%
   
112,500
   
59%
   
66,000
 

  Performance     20.5%     56,250          

  Discretionary     20.5%     56,250     117%     66,000  

        2014 Short-Term Incentive Plan.    In 2014, the Compensation Committee, with the advice of its compensation consultant, updated our 2013 Short-Term Incentive Plan. The Compensation Committee revised the DCF performance levels and incentive award opportunities associated with them based on the business objectives established for 2014. The 2014 STIP establishes a target incentive percentage for each participant ranging from 41% to 100% of base salary representing the same target percentages used during 2013 for the named executive officers. Awards under the 2014 STIP may range from 0% to 200% of each participant's target incentive percentage. The weightings of the STIP Performance Component and STIP Discretionary Component in the 2014 plan remain 50% and 50%, respectively, the same as in the 2013 STIP.

    The 2014 Performance Component (50% of the incentive target value)—The Compensation Committee increased the DCF objective for 2014, subject to adjustment by the Compensation Committee for certain acquisitions and events during 2014 that the Compensation Committee may, in its sole discretion, determine to have caused unusual, one-time increases or decreases in DCF. Awards granted by the Compensation Committee may range from 0% to 200% of a plan participant's 2014 STIP Performance Component. A minimum of 85% of the 2014 DCF objective must be achieved before plan participants would earn any portion of the 2014 STIP Performance Component. Under the 2014 STIP, a plan participant's incentive opportunity increases to a maximum of 200% of the STIP Performance Component at 130% of the 2014 DCF objective, and is determined on a quantitative basis solely based on our actual DCF for 2014.

    The Discretionary Component (50% of the incentive target value)—The Compensation Committee has discretion in determining the 2014 STIP Discretionary Component for any plan participant under the 2014 STIP, within a range of 0% to 200% of the 2014 STIP Discretionary Component,

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      and based upon (i) the Compensation Committee's consideration of management's performance over the course of the 2014 plan year; (ii) the CEO's assessment of other members of our management; (iii) our overall financial results for the year in relation to our business plan; and (iv) any significant mitigating factor(s) that may have influenced a plan participant's performance, positively or negatively. The objective of considering these factors is to arrive at a decision that best reflects the Compensation Committee's overall assessment of management's performance. The Compensation Committee believes that when combined with the STIP Performance Component, the results will more accurately reflect a plan participant's performance in light of the relevant factors.

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 did not award any discretionary bonus payments in 2013. The Compensation Committee awarded Messrs. Eric Slifka and Edward Faneuil special discretionary bonuses in the amounts of $200,000 and $59,375, respectively, for their service in 2012; and Messrs. Eric Slifka, Hollister, Faneuil and Rudinsky $270,000, $25,500, $97,500 and $32,500, respectively, for their service in 2011.

Long-Term Incentive Plans

        2013 Awards.    On June 27, 2013, the Compensation Committee granted 127,259, 76,356, 57,012, 29,537, 21,889 and 5,091 phantom units (without Distribution Equivalent Rights ("DERs")) under the LTIP, respectively, to Messrs. Eric Slifka, Faneuil, Romaine, Andrew Slifka, Ms. Foster and Mr. Rudinsky. On September 23, 2013, the Compensation Committee granted an additional 1,273 phantom units (without DERs) under the LTIP to Mr. Rudinsky. Grant levels were established by the Compensation Committee to achieve the overall objectives of the compensation program. Because no employee awards had been granted under the LTIP since 2009, the Compensation Committee used the 2013 awards to compensate recipients, based upon performance, for up to four years of service, two retrospective (2011 and 2012) and two prospective (2013 and 2014). Ms. Foster and Mr. Romaine received awards based upon the two prospective years only, because they began in their positions as CFO and COO, respectively, in 2013. Mr. Andrew Slifka received an award based upon three years of service (one retrospective and two prospective), because he began his employment with our general partner in 2012. Mr. Rudinsky's grant is based upon two and one-half years of service. Messrs. Eric Slifka and Faneuil received awards based upon four years of service. All phantom units granted in 2013 vest and became payable on a one-for-one basis in common units (and/or cash in lieu thereof). The units granted to each recipient other than Mr. Rudinsky vest over a six-year period, with one-third of the units granted to vest on each of July 1, 2017, July 1, 2018 and July 1, 2019. The units granted to Mr. Rudinsky vest over a three and one-half year period, with one-third of the units granted to vest on each of December 31, 2014, December 31, 2015 and December 31, 2016. Each recipient of a 2013 LTIP award has entered into (or already is subject to) a non-compete agreement with our general partner, and each recipient is entitled to accelerated vesting of the award units upon a change of control. Messrs. Rudinsky and Romaine and Ms. Foster are also party to executive change of control agreements with our general partner which include additional acceleration provisions. See "Employment and Related Agreements" for additional information with respect to executive change of control agreements.

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        2012 CEO Performance-Based Cash Incentive Plan.    Mr. Eric Slifka's 2012-2014 employment agreement with our general partner includes provisions for a long-term performance-based cash incentive plan. This plan replaced a three-year grant of phantom units to Mr. Slifka pursuant to his 2009-2011 employment agreement with our general partner, which vested in six approximately equal installments each June 30 and December 31 during the term of Mr. Slifka's 2009-2011 employment agreement. The long-term performance-based cash incentive plan is based solely on the achievement of growth in distributions to our unitholders over the term of Mr. Slifka's 2012-2014 employment agreement, using the three-year period from January 1, 2012 through December 31, 2014 and an annualized $2.00 per unit distribution to unitholders (subject to adjustment by the Compensation Committee as set forth in Mr. Slifka's employment agreement) as the baseline against which Mr. Slifka's performance will be measured.

        2009 Awards.    On February 5, 2009, the Compensation Committee granted 88,183, 61,728, 48,501, 26,455 and 17,637 phantom units (without DERs) under the LTIP, respectively, to Messrs. Eric Slifka, Hollister, Faneuil, Romaine and Rudinsky.

        The phantom units granted in 2009 vested and became payable on a one-for-one basis in common units (and/or cash in lieu thereof) as follows: 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. 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 final portion (50%) of the February 5, 2009 phantom units granted to our named executive officers vested on March 29, 2013 when the Compensation Committee determined that the third Average Unit Price condition ($34.00 for 10 consecutive trading days) was satisfied. In each instance, our general partner delivered common units that it purchased in the open market to the named executive officers in payment for these vested phantom units.

Retirement and Health Benefits; Perquisites

Global Partners 401(k) Savings and Profit Sharing

        The Global Partners LP 401(k) Savings and Profit Sharing Plan (the "Global 401(k) Plan") permits all eligible employees to make voluntary pre-tax contributions to the plan, subject to applicable tax limitations. During calendar years 2010, 2011 and 2012, our general partner was permitted to make a discretionary matching contribution to the Global 401(k) plan for each eligible employee. Effective January 1, 2013, our general partner amended the Global 401(k) Plan to remove the discretionary matching contributions and provide instead for employer matching contributions equal to 100% of elective deferrals up to the first 3% of eligible compensation plus 50% of elective deferrals up to the next 2% of eligible compensation. All employees are eligible to participate in the Global 401(k) Plan other than employees who (1) are not yet 21 years of age, (2) are covered by a collective bargaining agreement that does not provide for employees to be covered by the Global 401(k) Plan, (3) have not been employed by our predecessor, our general partner or one of our operating subsidiaries for at least six months or (4) are nonresident aliens. Eligible employees may elect to contribute up to 100% of their compensation to the plan for each plan year. Employee contributions are subject to annual dollar limitations, which are periodically adjusted for changes in the cost of living. Participants in the plan are always fully vested in any matching contributions under the plan; however, discretionary profit sharing contributions are subject to a six-year vesting schedule. The plan is intended to be tax-qualified under Section 401(a) of the Code so that contributions to the plan, and income earned on plan contributions, are not taxable to employees until withdrawn from the plan, and so that our general partner's contributions, if any, will be deductible when made.

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GMG 401(k) Savings and Profit Sharing

        As a result of the Alliance Acquisition, effective as of March 1, 2012, sponsorship of Alliance Energy LLC 401(k) Savings and Profit Sharing Plan was transferred to GMG, which is a part of our controlled group, and the name of the Plan was changed to the Global Montello Group Corp 401(k) Savings and Profit Sharing Plan (the "GMG 401(k) Plan"). The GMG 401(k) Plan permits all eligible employees to make voluntary pre-tax contributions to the plan, subject to applicable limitations under the Code. The GMG 401(k) Plan provides for employer matching contributions equal to 100% of elective deferrals up to the first 3% of eligible compensation plus 50% of elective deferrals up to the next 2% of compensation. Prior to January 1, 2013, all employees were eligible to participate in the GMG 401(k) Plan other than employees who (1) were not yet 21 years of age, (2) were covered by a collective bargaining agreement that does not provide for employees to be covered by the GMG 401(k) Plan, (3) had not been employed by GMG or a predecessor employer for at least six months or (4) were nonresident aliens. Effective as of January 1, 2013, the GMG 401(k) Plan was amended to require employees to have been employed by GMG or a predecessor employer for at least twelve months prior to enrollment in the GMG 401(k) Plan. Eligible employees may elect to contribute up to 100% of their compensation to the plan for each plan year. Employee contributions are subject to annual dollar limitations, which are periodically adjusted by the cost of living index. Participants in the plan are always fully vested in any matching contributions under the plan. The plan is intended to be tax-qualified under Section 401(a) of the Code so that contributions to the plan, and income earned on plan contributions, are not taxable to employees until withdrawn from the plan, and so that GMG's contributions, if any, will be deductible when made.

        Prior to March 1, 2012, Mr. Andrew Slifka was employed by Alliance and eligible to participate in Alliance's 401(k) plan. A final contribution to the former Alliance 401(k) plan, which has been renamed to reflect GMG's sponsorship, was made on behalf of Mr. Andrew Slifka in January 2013.

Pension Benefits

        Each of our named executive officers is eligible to participate in our general partner's pension plan in accordance with our general partner's policies and on the same general basis as other employees of our general partner. Under our general partner's pension plan, an employee becomes fully vested in his or her pension benefits after completing five years of service or, if earlier, upon termination due to death, disability or retirement after the first day of the month following the month in which the employee attains age 65. Certain employees are entitled to a supplemental benefit that vests over five years with 20% vesting annually on each December 31 through 2014. 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.

Other Benefits

        Each of our named executive officers is eligible to participate in our general partner's health insurance plans 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.

        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, tax and/or legal 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.

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        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, enhancing our "virtual pipeline" from the mid-continent region of the United States and Canada to refiners and other customers on the East and West coasts, expanding our distribution, marketing and sales of petroleum products, expanding our gasoline station and convenience store 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.

        Our long-term incentive plans (performance-based cash incentive plan and LTIP) provide incentives and reward eligible participants for the achievement of long-term objectives, facilitate the retention of key employees by aligning their incentives with our long-term performance, continue to make our compensation mix more competitive, and align 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.

Tax Deductibility of Compensation

        With respect to the deduction limitations imposed under Section 162(m) of the Internal Revenue Code of 1986, as amended (the "Code"), we are a limited partnership and do not meet the definition of a "corporation" under Section 162(m). Accordingly, such limitations do not apply to compensation paid to the named executive officers.

Compensation Committee Report

        The Compensation Committee has reviewed and discussed the Compensation Discussion and Analysis required by Item 402(b) of Regulation S-K with management. Based upon such review, the related discussions and such other matters deemed relevant and appropriate by the Compensation Committee, the Compensation Committee has recommended to the board of directors that the Compensation Discussion and Analysis be included in this Form 10-K.

    Kenneth I. Watchmaker (Chairman)
    Robert J. McCool
    David McKown

    March 31, 2014

Compensation Committee Interlocks and Insider Participation

        Since the formation of Global GP LLC and throughout the fiscal year ended December 31, 2013, the Compensation Committee of Global GP LLC's board of directors has comprised of Robert J. McCool, David McKown and Kenneth I. Watchmaker, none of whom are officers or employees of our general partner or any of its affiliates. Mr. Alfred Slifka served as the Chairman of the board of directors of our general partner until his death on March 9, 2014 and was an employee of Global Petroleum Corp., an entity which shares certain common ownership with the Partnership, until December 31, 2013. Mr. Richard Slifka serves as Vice Chairman of our general partner's board of directors and is also an employee of Global Petroleum Corp. Effective March 12, 2014, Richard Slifka has assumed the duties of Chairman of the board.

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Compensation of Named Executive Officers

        The following table sets forth certain information with respect to compensation during 2013, 2012 and 2011 of our named executive officers.


Summary Compensation Table

Name and Principal
Position
  Year   Salary
($)
  Bonus
($) (2)
  Non-Equity
Incentive Plan
Compensation
($) (3)
  Unit
Awards
($) (4)
  Change in
Pension Value
and Deferred
Nonqualified
Compensation
Earnings
($) (5)
  All Other
Compensation
($)
  Total ($)  

Eric Slifka

    2013     800,000         400,000     5,000,000         73,756     6,273,756  

President and

    2012     800,000     200,000     1,400,000         240,443     102,547     2,742,990  

CEO (1)(5)(6)

    2011     800,000     270,000     480,000             95,414     1,645,414  

Andrew Slifka

   
2013
   
425,000
   
   
100,000
   
1,160,500
   
   
49,002
   
1,734,502
 

EVP and President of Alliance Gasoline Division (5)(7)

    2012     425,000         300,000         64,511     28,031     817,542  

Thomas J. Hollister

   
2013
   
578,000
   
   
   
   
   
940,052
   
1,734,502
 

Former COO and

    2012     578,000         400,000         24,715     36,995     1,039,710  

CFO (5)(8)

    2011     578,000     25,500     202,500         1,939     29,951     837,890  

Daphne H. Foster Current CFO (9)

   
2013
   
246,500
   
   
100,000
   
860,000
   
   
20,668
   
1,227,168
 

Edward J. Faneuil

   
2013
   
376,000
   
   
175,000
   
3,000,000
   
   
36,891
   
3,587,891
 

EVP, General Counsel

    2012     376,000     59,375     240,625         99,675     56,211     831,886  

and Secretary (5)(10)

    2011     376,000     97,500     82,500         26,542     47,774     630,316  

Charles A. Rudinsky

   
2013
   
273,000
   
   
66,000
   
245,064
   
   
28,633
   
612,697
 

EVP and Chief Accounting

    2012     273,000         141,500         93,725     46,612     554,837  

Officer (5)(11)

    2011     273,000     32,500     67,500         38,553     35,719     447,272  

Mark A. Romaine Chief Operating Officer (12)

   
2013
   
450,000
   
   
250,000
   
2,240,000
   
   
30,965
   
2,970,965
 

(1)
The above table reflects the base salary paid to Mr. Eric Slifka in (i) 2011 pursuant to his employment agreement with our general partner that expired December 31, 2011, and (ii) 2012 and 2013 pursuant to his subsequent employment agreement with our general partner which became effective January 1, 2012, and pursuant to which his base salary remained $800,000.

(2)
No discretionary bonuses were paid for services performed during 2013. In 2013, Messrs. Eric Slifka and Faneuil were paid discretionary bonuses of $200,000 and $59,375, respectively, for services performed during 2012, which discretionary bonuses were in addition to the payments they received in 2013 for services performed during 2012 under the 2012 Short-Term Incentive Plan. In 2012, Messrs. Slifka, Hollister, Faneuil and Rudinsky were paid discretionary bonuses of $270,000, $25,500, $97,500 and $32,500, respectively, for services performed during 2011, which discretionary bonuses were in addition to the payments they received in 2012 for services performed during 2011 under the 2011 Short-Term Incentive Plan.

(3)
The bonuses paid to each of the named executive officers for services performed during 2013, 2012 and 2011 were determined in accordance with our general partner's Short-Term Incentive Plans described above under Elements of CompensationShort-Term Incentive Plans.

(4)
All of our equity grant awards were made under the Global Partners LP Long-Term Incentive Plan. Amounts disclosed in the table reflect the full grant date fair value of Partnership phantom units granted on June 27, 2013 or September 23, 2013, computed in accordance with ASC Topic 718, rather than the amounts paid to or realized by the named individual. In accordance with ASC Topic 718, the grant date fair value of these awards was calculated based upon the closing price per Global Partners LP common unit on the date of grant. There can be no assurance that awards will vest (and, absent vesting, no value will be realized by the executive for the invested award), or that the value upon vesting will approximate the aggregate grant date fair value determined under ASC Topic 718.

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(5)
As a result of higher interest rates used to calculate pension benefits, the present value of Mr. Eric Slifka's pension decreased by $53,379 in 2013 and $11,068 in 2011, and the present values of the pensions of Messrs. Andrew Slifka, Hollister, Faneuil and Rudinsky decreased in 2013 by $31,277, $5,343, $20,580 and $57,755, respectively. These decreases are shown as a $0 positive change in actuarial value for those years under the column labeled "Change in Pension Value and Nonqualified Deferred Compensation Earnings". Ms. Foster is ineligible to participate in our general partner's pension plan.

(6)
With respect to Mr. Eric Slifka, "All Other Compensation" for the years ended December 31, 2013, 2012 and 2011 includes the following perquisites in connection with his employment by our general partner: employer contributions paid by us under our general partner's 401(k) plan in the amounts of $5,333, $12,667 and $14,700, respectively, for 2013, 2012 and 2011; the estimated incremental cost of an automobile provided by us for Mr. Slifka's use; medical and dental premiums paid by us; life insurance and long-term disability insurance premiums paid by us; club membership dues; legal fees; and professional financial planning and tax advice fees paid by us in the aggregate amounts of $26,750, $36,386 and $26,450, respectively, for 2013, 2012 and 2011.

(7)
Mr. Andrew Slifka was employed by Alliance prior to March 1, 2012. With respect to Mr. Slifka, "All Other Compensation" for the years ended December 31, 2013 and 2012 includes the following perquisites in connection with his employment by our general partner: employer contributions paid by us under our general partner's 401(k) plan in the amount of $9,000 and $11,800 respectively for 2013 and 2012; the estimated incremental cost of an automobile provided by us for Mr. Slifka's use; medical and dental premiums paid by us; and life insurance and long-term disability insurance premiums paid by us. Mr. Slifka's employment agreement with our general partner also provides for payment by us of club membership dues and professional financial planning and tax advice fees on behalf of Mr. Slifka. Mr. Slifka received $20,750 in 2013 but did not receive any amount of this perquisite in 2012.

(8)
With respect to Mr. Hollister, who retired on June 30, 2013, "All Other Compensation" for the years ended December 31, 2013, 2012 and 2011 includes the following in connection with his employment by our general partner: cash severance in the amount of $867,000 payable during 2014 and 2015 in connection with his separation from employment during 2013, employer contributions paid by us under our general partner's 401(k) plan in the amounts of $10,200, $10,963 and $12,250, respectively, for 2013, 2012 and 2011; the estimated incremental cost of an automobile provided by us for Mr. Hollister's use; medical and dental premiums paid by us; life insurance and long-term disability insurance premiums paid by us; a one-time cash payment to Mr. Hollister in the amount of $28,526.46 as compensation for accrued, unused vacation time through June 30, 2013; and in connection with Mr. Hollister's retirement, consulting and noncompetition arrangements with our general partner, cash payments of $35,500 in the aggregate in lieu of life insurance, disability, long-term health care or similar policy premiums to replace benefits that terminated effective December 31, 2013.

(9)
With respect to Ms. Foster, "All Other Compensation" for the year ended December 31, 2013 includes the following in connection with her employment by our general partner: employer contributions paid by us under our general partner's 401(k) plan in the amount of $8,233 for 2013; the estimated incremental cost of an automobile provided by us for Ms. Foster's use; and life insurance and long-term disability insurance premiums paid by us.

(10)
With respect to Mr. Faneuil, "All Other Compensation" for the years ended December 31, 2013, 2012 and 2011 includes the following in connection with his employment by our general partner: employer contributions paid by us under our general partner's 401(k) plan in the amounts of $9,777, $11,253 and $14,700, respectively for 2013, 2012 and 2011; the estimated incremental cost of an automobile provided by us for Mr. Faneuil's use; medical and dental premiums paid by us; life insurance and long-term disability insurance premiums paid by us; and club membership dues paid by us.

(11)
With respect to Mr. Rudinsky, "All Other Compensation" for the years ended December 31, 2013, 2012 and 2011 includes the following in connection with his employment by our general partner: employer contributions paid by us under our general partner's 401(k) plan in the amounts of $10,200, $10,910 and $14,700, respectively for 2013, 2012 and 2011; a one-time cash payment to Mr. Rudinsky in the amount of $15,000 paid in 2012 in connection with the inability to make non-elective contributions to highly compensated employees under our general partner's 401(k) plan; the estimated incremental cost of an automobile provided by us for Mr. Rudinsky's use; medical and dental premiums paid by us; and life insurance and long-term disability insurance premiums paid by us.

(12)
With respect to Mr. Romaine, "All Other Compensation" for the year ended December 31, 2013 includes the following in connection with his employment by our general partner: employer contributions paid by us under our general partner's 401(k) plan in the amount of $6,583 for 2013; the estimated incremental cost of an automobile provided by us for Mr. Romaine's use; medical and dental premiums paid by us; and life insurance and long-term disability insurance premiums paid by us.

Grants of Plan-Based Awards

        During 2013, the Compensation Committee granted cash awards under our general partner's 2013 Short-Term Incentive Plan to our named executive officers (other than Mr. Hollister, who retired on

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June 30, 2013) in consideration of their respective services during the year ended December 31, 2013. During 2014, the Compensation Committee determined that these awards had been earned in the following amounts: $400,000 for Mr. Eric Slifka, $250,000 for Mr. Romaine, $175,000 for Mr. Faneuil, $100,000 for Mr. Andrew Slifka, $100,000 for Ms. Foster and $66,000 for Mr. Rudinsky. These awards are expected to be paid during the second quarter of 2014. See "Elements of CompensationShort-Term Incentive Plan" for a discussion of the parameters on which the 2013 awards were determined.

        On June 27, 2013, the Compensation Committee awarded phantom unit awards under our general partner's 2013 Long-Term Incentive Plan to our named executive officers (other than Mr. Hollister, who retired on June 30, 2013) in consideration of their respective services during the year ended December 31, 2013. On September 23, 2013, the Compensation Committee made a supplemental award of phantom units under our general partner's Long-Term Incentive Plan to Mr. Rudinsky. See "Elements of CompensationLong-Term Incentive Plan" for a description of the vesting schedules for these awards.

        The following table sets forth information concerning the grant of plan-based awards during the calendar year 2013 to our named executive officers from the Partnership's (i) Short-Term Incentive Plan (including the minimum threshold, target and maximum possible payout amounts, depending upon our financial performance in 2013), and (ii) Long-Term Incentive Plan.


Grants of Plan-Based Awards

 
  Estimated Possible Payouts Under
Non-Equity Incentive Plan Awards
   
   
   
 
 
   
   
  Grant Date
Fair Value
of Unit
Awards
($) (2)
 
 
   
  All Other
Awards—
Number of
Units (1)
 
Name
  Minimum
Threshold
($)
  Target ($)   Maximum
($)
  Grant Date  

Eric Slifka

    40,000     800,000     1,600,000     06/27/13     127,259     5,000,000  

Andrew Slifka

   
10,000
   
200,000
   
400,000
   
06/27/13
   
29,537
   
1,160,500
 

Thomas J. Hollister

   
   
   
   
   
   
 

Daphne H. Foster

   
10,000
   
200,000
   
400,000
   
06/27/13
   
21,889
   
860,000
 

Edward J. Faneuil

   
17,500
   
350,000
   
700,000
   
06/27/13
   
76,356
   
3,000,000
 

Charles A. Rudinsky

   
5,625
   
112,500
   
225,000
   
06/27/13
   
5,091
   
200,000
 

                      09/23/13     1,273     45,064  

Mark A. Romaine

   
25,000
   
500,000
   
1,000,000
   
06/27/13
   
57,012
   
2,240,000
 

(1)
All of our equity grant awards were made under the Global Partners LP Long-Term Incentive Plan. Amounts disclosed in the table reflect the full grant date fair value of Partnership phantom units granted on June 27, 2013 or September 23, 2013, computed in accordance with ASC Topic 718, rather than the amounts paid to or realized by the named individual. In accordance with ASC Topic 718, the grant date fair value of these awards was calculated based upon the closing price per Global Partners LP common unit on the date of grant. There can be no assurance that awards will vest (and, absent vesting, no value will be realized by the executive for the unvested award), or that the value upon vesting will approximate the aggregate grant date fair value determined under ASC Topic 718.

(2)
All phantom units granted in 2013 vest and became payable on a one-for-one basis in common units (and/or cash in lieu thereof). The units granted to each recipient other than Mr. Rudinsky vest over a six-year period, with one-third of the units granted scheduled to vest on each of July 1, 2017, July 1, 2018 and July 1, 2019. The units granted to Mr. Rudinsky vest over a three and one-half year period, with one-third of the units granted scheduled to vest on each of December 31, 2014, December 31, 2015 and December 31, 2016. The June 27, 2013 closing price was $39.29 per Global Partners LP common unit. The September 23, 2013 closing price was $35.40 per Global Partners LP common unit.

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Outstanding Equity Awards at Fiscal Year End

        The following table presents the full amount of the equity awards held by our named executive officers (other than Mr. Hollister, who retired on June 30, 2013 and who did not hold any outstanding equity awards at the time of his retirement) in the form of phantom units granted under the LTIP. The awards shown on the table below were the only equity awards held by the named executive officers at the end of the last fiscal year, and no portion of these awards had vested as at December 31, 2013:

 
  Equity Incentive Plan Awards  
 
  Number of
Unearned Shares,
Units or Other
Rights That Have
Not Vested (#) (1)
  Market or Payout
Value of
Unearned Shares,
Units or Other
Rights That Have
Not Vested ($) (2)
 

Eric Slifka

    127,259     4,503,696  

Andrew Slifka

    29,537     1,045,314  

Thomas J. Hollister

         

Daphne H. Foster

    21,889     774,652  

Edward J. Faneuil

    76,356     2,702,239  

Charles A. Rudinsky

    6,364     225,222  

Mark A. Romaine

    57,012     2,017,655  

(1)
The units granted to each recipient other than Mr. Rudinsky vest over a six-year period, with one-third of the units granted to vest on each of July 1, 2017, July 1, 2018 and July 1, 2019. The units granted to Mr. Rudinsky vest over a three and one-half year period, with one-third of the units granted to vest on each of December 31, 2014, December 31, 2015 and December 31, 2016.

(2)
The market values of the equity awards shown in the table above were calculated based on the closing price of $35.39 per common unit on December 31, 2013.

        See "Elements of Compensation—Long-Term Incentive Plan" for a discussion of these phantom unit awards.

    Units Vested in the 2013 Fiscal Year

        The following table presents phantom units awarded to the named executive officers on February 5, 2009 that vested during the year ended December 31, 2013.

 
  Equity Incentive Plan Awards  
 
  Number of
Vested
Phantom Units
  Market Value of
Vested
Phantom Units (#) ($) (1)
 

Eric Slifka

    44,091     1,644,153  

Andrew Slifka

         

Thomas J. Hollister

    30,864     1,150,919  

Daphne H. Foster

         

Edward J. Faneuil

    24,251     904,320  

Charles A. Rudinsky

    8,819     328,861  

Mark A. Romaine

    13,229     493,309  

(1)
These units vested on March 19, 2013, when the average closing price per unit for any 10-consecutive trading day period during the period from June 5, 2012 through December 31, 2013 reached $34.00. The market values of the equity awards shown in the table above were calculated based on the closing price of $37.29 per common unit on March 19, 2013.

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    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 subsequent employment agreement with our general partner which commenced January 1, 2009 and continued through December 31, 2011 (the "2008 Agreement"). Effective January 1, 2012, Mr. Slifka entered into a new employment agreement with our general partner which supersedes each of his prior two agreements (the "2012 Agreement").

        Like the 2008 Agreement, the 2012 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, both agreements provide that Mr. Slifka: is (a) eligible to receive a cash bonus, from time to time, in an amount to be determined at the discretion of the Compensation Committee and (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 quarter 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. Similarly, both agreements provide that Mr. Slifka also may be eligible to participate in any other incentive plans in which management employees may participate, as determined by the Compensation Committee. He is entitled to participate in such other benefit plans and programs as our general partner may provide for its executives in general.

        Mr. Slifka was entitled under the 2008 Agreement 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 us from time to time), which became fully vested as of December 31, 2011, and (ii) the February 5, 2009 grant to Mr. Slifka of 88,183 performance-restricted phantom units under the LTIP. Under the 2012 Agreement, Mr. Slifka remains entitled to participate in our general partner's LTIP, including without limitation the June 27, 2013 grant to Mr. Slifka of 127,259 phantom units under the LTIP. See "Elements of Compensation—Long-Term Incentive Plan." Under the 2012 Agreement, Mr. Slifka also is entitled to receive awards under our general partner's Long-Term Performance-Based Cash Incentive Plan, the amount of which is determined based upon the achievement of distribution growth to the Partnership's unitholders over the term of his employment agreement, using the 3-year period from January 1, 2012 through December 31, 2014 and an annualized $2.00 per unit distribution to unitholders as the baseline against which Mr. Slifka's performance will be measured.

        Mr. Slifka's current 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 nonsolicitation and non-competition provisions which will continue 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.

        Andrew P. Slifka is employed as Executive Vice President of our general partner and President of the Alliance Gasoline Division of the Partnership, pursuant to an employment agreement with our general partner. Mr. Slifka's initial employment agreement became effective as of March 1, 2012 and continues for a thirty-six (36) month term. Mr. Slifka's employment agreement was negotiated in connection with the Partnership's acquisition of Alliance Energy LLC, and was not evaluated by the Compensation Committee in connection with that acquisition.

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        Mr. Slifka's employment agreement provides for a base salary of $425,000 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 also provides that Mr. Slifka is (a) eligible to receive a cash bonus, from time to time, in an amount to be determined at the discretion of the Compensation Committee and (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, 50% of which shall be determined based upon the achievement of financial metrics to be established by the Compensation Committee in the first quarter of each fiscal year during the term of the agreement, and 50% of which shall be determined at the discretion of the Compensation Committee in the first quarter of each fiscal year during the term of the agreement, with the annual "award target" amount being $200,000 and the annual maximum cash incentive amount that may be awarded being $400,000; any such awards to be paid within two and one-half months after the applicable fiscal year end. Pursuan