Global Partners 10K 2013 Annual report

Global Partners (GLP) 10-K2013 FY Annual report

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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 Noý

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yeso Noý

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. Yeso Noo

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. Yesý Noo

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 filero		Accelerated filerý		Non-accelerated filero		Smaller reporting companyo

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yeso Noý

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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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

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:



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 than¹/2%

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

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

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.

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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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.

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.

Gasoline Distribution and Station Operations

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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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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:

•: 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:

•: 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.

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.

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 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 inInternal 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		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 atwww.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 (50^th percentile) and 75^th 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

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

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 underElements of Compensation—Short-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 Compensation—Short-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 Compensation—Long-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		All Other Awards— Number of Units (1)
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. Pursuant to his employment agreement, Mr. Slifka also may participate in our general partner's LTIP, in such forms and amounts as may be determined by the Compensation Committee. Similarly, his employment agreement provides 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'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 noncompetition 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.

Thomas J. Hollister retired from his employment with our general partner as Chief Operating Officer and Chief Financial Officer on June 30, 2013. Prior to his retirement, Mr. Hollister entered into a Retirement, Consulting and Noncompete Agreement (the "2013 Agreement") pursuant to which Mr. Hollister (i) continued to receive his base salary through December 31, 2013, and (ii) participated in our general partner's health insurance, pension, 401(k), long-term disability, life insurance 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, but (iii) was not eligible for, did not accrue, earn or participate in any Bonus or LTIP or in any Short-Term Incentive Plan. Pursuant to the 2013 Agreement, Mr. Hollister also (i) received his accrued unused vacation and (ii) commencing January 1, 2014, is entitled to receive a monthly gross amount equal to $48,166.66 for a period of eighteen months. The 2013 Agreement includes (i) 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. Hollister), prohibits Mr. Hollister from disclosing confidential information of the Partnership or our general partner without the written consent of the board of directors of our general partner or a person authorized in writing thereby, and (ii) non-competition provisions which continue for a period of two years from his last day of employment with our general partner. The 2013 Agreement was subsequently modified by a memorandum dated July 9, 2013, whereby Mr. Hollister agreed that his active participation in certain benefit plans would terminate on December 31, 2013 and that h- would receive an additional cash payment in the amount of $25,000 as well as up to $10,000 in reimbursement for the cost of purchasing life insurance, disability, long term health care or similar like policy premiums on his behalf.

Daphne H. Foster, Chief Financial Officer, is an at will employee and does not have an employment agreement with our general partner. Commencing July 1, 2013, Ms. Foster's base salary was increased from $200,000 to $300,000. Effective July 1, 2013, Ms. Foster entered into a Change of

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Control Agreement with our general partner which, in the event of a "Change of Control" (defined below), provides for accelerated vesting of any and all outstanding company options, restricted units, phantom units, unit appreciation rights and other similar rights under the LTIP held by her as in effect on the date of the Change of Control. Pursuant to the Change of Control Agreement, a "Change of Control" is deemed to occur on the date that any one person, entity or group (other than Richard Slifka or Eric Slifka, or their respective family members or entities they control, individually or in the aggregate, directly or indirectly) acquires ownership of the membership interests of our general partner that, together with the membership interests of our general partner already held by such person, entity or group, constitutes more than 50% of the total voting power of the membership interests of our general partner. The Change of Control Agreement also provides that in the event of termination of Ms. Foster's employment by our general partner without cause or by Ms. Foster for good reason, as those terms are defined in the Change of Control Agreement, Ms. Foster shall receive payment through the date of termination of her employment of (i) any earned, but unpaid, base salary as then in effect, (ii) all earned, but unpaid, bonuses, (iii) all accrued vacation, expense reimbursements and other benefits (other than severance), and (iv) any and all other amounts that may be due to her as of the date of termination. In the event of such termination, the Change of Control Agreement also provides for (i) acceleration of the target incentive amount under the then applicable short-term incentive plan for the fiscal year in which the termination occurs, and (ii) 100% vesting of any and all outstanding company options, restricted units, phantom units, unit appreciation rights and other similar rights under the Long-Term Incentive Plan held by Ms. Foster as in effect on the date of termination. In connection with her entering into the Change of Control Agreement, Ms. Foster also agreed to two-year post-termination noncompetition and nonsolicitation covenants.

Edward J. Faneuil is employed as Executive Vice President, General Counsel and Secretary pursuant to an employment agreement with our general partner. Mr. Faneuil's employment agreement became effective as of July 1, 2006 and pursuant to an amendment dated December 31, 2011, has been extended through December 31, 2014. In 2011, Mr. Faneuil's base salary was $376,000. Pursuant to the terms of his agreement, Mr. Faneuil's base salary is reviewed by the Compensation Committee at least annually. Mr. Faneuil also is entitled to receive bonuses in accordance with the then applicable short-term incentive plan as authorized by the Compensation Committee to be paid no later than March 15 of the calendar year immediately following the calendar year in which such bonuses are earned. Mr. Faneuil is eligible to participate in our general partner's health insurance, pension, 401(k) and other employee benefit plans and will also receive additional fringe benefits consistent with benefits previously provided to him under prior arrangements. Mr. Faneuil is eligible to participate in the LTIP on the same general basis as the other executive officers of our general partner. The agreement includes a confidentiality provision which, subject to typical exceptions for requirements of law and public knowledge (other than as a result of unauthorized disclosure by Mr. Faneuil), will continue for two years following Mr. Faneuil's termination of employment. The agreement also includes non-competition and non-solicitation provisions which continue during the term of the agreement and for a period of two years thereafter. Mr. Faneuil also has entered into deferred compensation agreements with each of our general partner and Alliance. See "—Deferred Compensation Agreements" below for a description of these non-qualified deferred compensation plans. Mr. Faneuil also has entered into a supplemental executive retirement plan ("SERP") agreement with our general partner to provide him with supplemental retirement benefits in consideration of past and future services provided by him and in recognition of his ineligibility to participate in our increased retirement benefits program in connection with the freezing of benefits under our general partner's pension plan. See "—Supplemental Executive Retirement Plan Agreements" for a discussion of the provisions in Mr. Faneuil's SERP agreement. See "Potential Payments Upon Termination or Change of Control" for a discussion of the provisions in Mr. Faneuil's employment agreement, as amended, and in his amended and restated deferred compensation agreements relating to termination, change of control and related payment obligations.

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Charles A. Rudinsky, Executive Vice President and Chief Accounting Officer, is an at will employee and does not have an employment agreement with our general partner. In 2013, Mr. Rudinsky's base salary was $273,000. Mr. Rudinsky also has entered into a SERP agreement with our general partner to provide him with supplemental retirement benefits in consideration of past and future services provided by him and in recognition of his ineligibility to participate in our increased retirement benefits program in connection with the freezing of benefits under our general partner's pension plan. Upon reaching normal retirement age, Mr. Rudinsky acquired a fully vested and nonforfeitable interest in his SERP benefit and in our general partner's pension plan. The SERP benefit was paid out to him in 2012, and a portion of the pension benefit was paid out in 2013. See "—Supplemental Executive Retirement Plan Agreements" for a discussion of the provisions in Mr. Rudinsky's SERP agreement. Effective July 1, 2013, Mr. Rudinsky entered into an Executive Change of Control Agreement (the "Change of Control Agreement") with our general partner which, in the event of a "Change of Control" (defined below), provides for accelerated vesting of any and all outstanding Company options, restricted units, phantom units, unit appreciation rights and other similar rights under the LTIP held by him as in effect on the date of the Change of Control. Pursuant to the Change of Control Agreement, a "Change of Control" is deemed to occur on the date that any one person, entity or group (other than Richard Slifka or Eric Slifka, or their respective family members or entities they control, individually or in the aggregate, directly or indirectly) acquires ownership of the membership interests of our general partner that, together with the membership interests of our general partner already held by such person, entity or group, constitutes more than 50% of the total voting power of the membership interests of our general partner. The Change of Control Agreement also provides that in the event of termination of Mr. Rudinsky's employment by our general partner without cause or by Mr. Rudinsky for good reason, as those terms are defined in the Change of Control Agreement, Mr. Rudinsky shall receive payment through the date of termination of his employment of (i) any earned, but unpaid, base salary as then in effect, (ii) all earned, but unpaid, bonuses, (iii) all accrued vacation, expense reimbursements and other benefits (other than severance), and (iv) any and all other amounts that may be due to him as of the date of termination. In the event of such termination, the Change of Control Agreement also provides for (i) acceleration of the target incentive amount under the then applicable short-term incentive plan for the fiscal year in which the termination occurs, and (ii) 100% vesting of any and all outstanding Company options, restricted units, phantom units, unit appreciation rights and other similar rights under the Long-Term Incentive Plan held by Mr. Rudinsky as in effect on the date of termination. In connection with his entering into the Change of Control Agreement, Mr. Rudinsky also agreed to two-year post-termination noncompetition and nonsolicitation covenants.

Mark A. Romaine, Chief Operating Officer, is an at will employee and does not have an employment agreement with our general partner. Commencing July 1, 2013, Mr. Romaine's base salary was increased from $400,000 to $500,000. Effective July 1, 2013, Mr. Romaine entered into a Change of Control Agreement with our general partner which, in the event of a "Change of Control" (defined below), provides for accelerated vesting of any and all outstanding Company options, restricted units, phantom units, unit appreciation rights and other similar rights under the LTIP held by him as in effect on the date of the Change of Control. Pursuant to the Change of Control Agreement, a "Change of Control" is deemed to occur on the date that any one person, entity or group (other than Richard Slifka or Eric Slifka, or their respective family members or entities they control, individually or in the aggregate, directly or indirectly) acquires ownership of the membership interests of our general partner that, together with the membership interests of our general partner already held by such person, entity or group, constitutes more than 50% of the total voting power of the membership interests of our general partner. The Change of Control Agreement also provides that in the event of termination of Mr. Romaine's employment by our general partner without cause or by Mr. Romaine for good reason, as those terms are defined in the Change of Control Agreement,Mr. Romaine shall receive payment through the date of termination of his employment of (i) any earned, but unpaid, base salary as then in effect, (ii) all earned, but unpaid, bonuses, (iii) all accrued vacation, expense reimbursements and other

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benefits (other than severance), and (iv) any and all other amounts that may be due to him as of the date of termination. In the event of such termination, the Change of Control Agreement also provides for (i) acceleration of the target incentive amount under the then applicable short-term incentive plan for the fiscal year in which the termination occurs, and (ii) 100% vesting of any and all outstanding Company options, restricted units, phantom units, unit appreciation rights and other similar rights under the Long-Term Incentive Plan held by Mr. Romaine as in effect on the date of termination. In connection with entry in the Change of Control Agreement, Mr. Romaine also agreed to two-year post-termination noncompetition and nonsolicitation covenants.

Nonqualified Deferred Compensation

Mr. Romaine, our COO, previously agreed to receive his 2010, 2011 and 2012 bonus payments in installments over three years for each bonus. The table below shows the aggregate installment payments for prior years' bonus payments received by Mr. Romaine in 2013 and the aggregate sum of installment payments to be paid to Mr. Romaine after 2013 in respect of his prior bonuses.

Nonqualified Deferred Compensation

Name		Aggregate Withdrawals / Distributions (1)			Aggregate Balance at Last FY End (2)

Mark A. Romaine		$	450,000		$	675,000

(1): The amount reported in this column reflects the deferred installment payments of the bonuses earned by Mr. Romaine in 2010 and 2011 that were paid to Mr. Romaine in 2013.
(2): The amount reported in this column reflects the aggregate sum of deferred installment payments to be paid to Mr. Romaine after 2013 in respect of his 2012 bonus.

Deferred Compensation Agreements

On December 31, 2008, our general partner and Edward J. Faneuil entered into a deferred compensation agreement pursuant to which Mr. Faneuil will be subject to terms and conditions relating to confidential information, non-solicitation and non-competition, as provided therein (the "Global Deferred Compensation Agreement"). See "Potential Payments Upon Termination or Change of Control" for a discussion of the provisions in Mr. Faneuil's deferred compensation agreement relating to termination, change of control and related payment obligations.

On September 23, 2009, Alliance and Mr. Faneuil entered into a deferred compensation agreement pursuant to which Mr. Faneuil will be subject to terms and conditions relating to confidential information, non-solicitation and non-competition, as provided therein (the "Alliance Deferred Compensation Agreement"). See "Potential Payments Upon Termination or Change of Control" for a discussion of the provisions in Mr. Faneuil's deferred compensation agreement relating to termination, change of control and related payment obligations.

Supplemental Executive Retirement Agreement

On December 31, 2009, our general partner entered into SERP agreements with each of Edward J. Faneuil and Charles A. Rudinsky. Mr. Rudinsky's SERP benefit vested and was paid to him in 2012. The value of the SERP benefit to be provided under the agreements, expressed as a single lump sum payment, will be $159,355 for Mr. Faneuil. Mr. Faneuil will acquire a fully vested and nonforfeitable interest in his SERP benefit only to the extent he is continuously employed with our general partner from December 31, 2009 through the vesting dates set forth in his agreement, or if he dies or becomes Disabled (as such term is defined in the agreements) or if there is a Change in Control (as such term is defined in the agreements). See "Potential Payments Upon Termination or Change of Control" for a discussion of the provisions in Mr. Faneuil's SERP agreement relating to termination, change of control and related payment obligations.

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Potential Payments upon a Change of Control or Termination

The following table shows potential payments to our named executive officers (with the exception of Mr. Hollister, our former Chief Operating Officer and Chief Financial Officer, who retired on June 30, 2013) under existing contracts, agreements, plans or arrangements, whether written or unwritten, for various scenarios involving a change of control or termination of employment of each such named executive officer assuming a December 31, 2013 termination date. Amounts shown with respect to Mr. Hollister reflect the actual amounts payable in connection with his retirement during 2013. Amounts reflected in the table below with respect to LTIP awards were calculated based on the closing price of our common units of $35.39 per unit on December 31, 2013.

							Termination by general partner without Cause / Constructive Termination / Breach by general partner

Name	Change in Control ($)		Death ($)		Disability ($)		No Change in Control ($)		With a Change in Control ($)		Nonrenewal ($)
Eric Slifka (1)
Severance Amount		—		3,200,000		3,200,000		3,200,000		4,800,000		800,000
Long Term Cash Incentive Plan		—		2,300,000		2,300,000		2,300,000		2,300,000		—
LTIP awards (8)		4,503,696		—		—		—		4,503,696		—
Fringe benefits		—		32,404		32,404		32,404		32,404		—
Life insurance benefits		—		225,000		—		—		—		—


Total		4,503,696		5,757,404		5,532,404		5,532,404		11,636,100		800,000
Andrew Slifka (2)
Severance Amount		—		531,250		1,000,000		1,000,000		1,000,000		468,750
LTIP awards (8)		1,045,314		—		—		—		1,045,314		—
Fringe benefits		—		61,252		61,252		61,252		61,252		—
Life insurance benefits		—		225,000		—		—		—		—


Total		1,045,314		817,502		1,061,252		1,061,252		2,106,567		468,750
Thomas J. Hollister (4)
Cash Retirement Payments	$	1,191,500	$	1,191,500	$	1,191,500	$	1,191,500	$	1,191,500		—
Total	$	1,191,500	$	1,191,500	$	1,191,500	$	1,191,500	$	1,191,500		—
Daphne H. Foster (3)
LTIP awards (8)		774,652		—		—		—		774,652		—
Fringe benefits		20,668		—		—		20,668		20,668		—
Life insurance benefits		—		225,000		—		—		—		—
Total		795,320		225,000		—		20,668		795,320		—
Edward J. Faneuil (5)
Severance Amount		—		—		—		752,000		1,452,000		—
Deferred Compensation		1,691,816		1,691,816		1,691,816		1,691,816		1,691,816		—
SERP benefit		159,355		159,355		159,355		127,484		127,484		—
LTIP awards (8)		2,702,239		—		—		—		2,702,239		—
Fringe benefits		—		—		—		36,891		36,891		—
Life insurance benefits		—		225,000		—		—		—		—


Total		4,553,410		2,076,171		1,851,171		2,608,191		6,010,430		—
Charles A. Rudinsky (6)
LTIP awards (8)		225,222		—		—		—		225,222		—
Fringe benefits		28,633		—		—		28,633		28,633		—
Life insurance benefits		—		350,000		—		—		—		—


Total		253,855		350,000		—		28,633		253,855		—
Mark A. Romaine (7)
LTIP awards (8)		2,017,655		—		—		—		2,017,655		—
Unpaid deferred bonus installments		924,500		924,500		924,500		924,500		924,500		—
Fringe benefits		30,965		—		—		30,965		30,965		—
Life insurance benefits		—		225,000		—		—		—		—


Total		2,973,120		1,149,500		924,500		954,465		2,973,120		—

(1): Eric Slifka

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Assuming that Mr. Slifka's employment was terminated on December 31, 2013, the employment agreement between our general partner and Mr. Slifka provides that, upon termination of his employment for any reason, he would have been entitled to receive (i) all amounts of his base salary due and owing up through the date of termination, (ii) any earned but unpaid bonus, (iii) all reimbursements of expenses appropriately and timely submitted, and (iv) any and all other amounts that may be due to him as of the date of termination (the "Accrued Obligations").

If Mr. Slifka's employment had been terminated by death or "Disability" (defined below) on December 31, 2013, within 10 days following such termination he (or his estate) would have been entitled to receive in addition to any Accrued Obligations:

(i): a lump sum payment of $1,600,000 (equal to his then base salary multiplied by 200%); plus
(ii): a lump sum payment of $1,600,000 (equal to his target incentive amount under the short-term incentive plan multiplied by 200%); plus
(iii): his interests in our general partner's long-term incentive plans, as described below.

Additionally, our general partner would have continued the monthly payment of all group health and similar insurance premiums on behalf of his spouse and dependents for 24 months following the date of termination. For purposes of Mr. Slifka's employment agreement, "Disability" is defined as a physical or mental condition which (a) renders Mr. Slifka, with or without reasonable accommodation, unable to engage in any substantial gainful activity by reason of any medically determinable physical or mental impairment which can be expected to result in death or can be expected to last for a continuous period of not less than 12 months, or (b) by reason of any medically determinable physical or mental impairment which can be expected to result in death or can be expected to last for a continuous period of not less than 12 months, results in Mr. Slifka receiving income replacement benefits for a period of not less than 3 months under an accident and health plan covering employees of our general partner.

Assuming Mr. Slifka's employment had been terminated by our general partner without cause or by Mr. Slifka for reasons constituting "Constructive Termination" (defined below) on December 31, 2013, within 10 days following such termination he would have been entitled to receive in addition to any Accrued Obligations:

(i): a lump sum payment of $1,600,000 (an amount equal to his then base salary multiplied by 200%); provided, however, that the lump sum payment would be increased to $2,400,000 (an amount equal to his then base salary multiplied by 300%) if such termination were for reasons constituting Constructive Terminationand such termination occurred within 12 months following a "Change in Control" (defined below); plus
(ii): a lump sum payment of $1,600,000 (an amount equal to his target incentive amount under the then applicable Short-Term Incentive Plan multiplied by 200%); provided, however, that the lump sum payment would be increased to $2,400,000 (an amount equal to his target incentive amount under the then applicable Short-Term Incentive Plan multiplied by 300%) if such termination were for reasons constituting Constructive Terminationand such termination occurred within 12 months following a "Change in Control" (defined below); plus
(iii): his interests in our general partner's long-term incentive plans, as described below.

Also, our general partner would have continued the monthly payment of all group health and similar insurance premiums on behalf of Mr. Slifka's spouse and dependents for 24 months following the date of termination. For purposes of Mr. Slifka's employment agreement, "Constructive Termination" means termination of employment as a result of (a) any substantial diminution, without Mr. Slifka's written consent, in his working conditions consisting of (i) a material reduction in his duties and responsibilities, (ii) any change in the reporting structure so that he no longer reports solely to our Board of Directors, or (iii) a relocation of his place of work further than 40 miles from Waltham, Massachusetts, or (b) an uncured breach by our general partner of a material provision of the employment agreement, as amended. Pursuant to Mr. Slifka's employment agreement, a "Change in

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Control" would be deemed to have occurred upon (1) the date that any one person, entity or group (other than Alfred Slifka, Richard Slifka or Eric Slifka, or their respective family members or entities they control, individually or in the aggregate, directly or indirectly) acquires ownership of the membership interests of our general partner that, together with the membership interests of our general partner already held by such person, entity or group, constitutes more than 50% of the total fair market value or total voting power of the membership interests of our general partner; provided, however, if any one person, entity or group is considered to own more than 50% of the total fair market value or total voting power of the membership interests of our general partner, the acquisition of additional membership interests by the same person, entity or group shall not be deemed to be a Change in Control; (2) a consolidation or merger (in one transaction or a series of related transactions) of our general partner pursuant to which the holders of our general partner's equity securities immediately prior to such transaction or series of related transactions would not be the holders immediately after such transaction or series of related transactions of at least 50% of the voting power of the entity surviving such transaction or series of related transactions; or (3) the sale, lease, exchange or other transfer (in one transaction or a series of related transactions) of all or substantially all of our business and/or assets to a person other than Richard Slifka or Eric Slifka, or their respective family members or entities they control, individually or in the aggregate, directly or indirectly.

With respect to Mr. Slifka's interests in our general partner's long-term incentive plans, assuming, at December 31, 2013, that there has been a Change in Control, then all outstanding and unvested phantom units that were granted to Mr. Slifka under our LTIP on June 27, 2013 automatically would have become fully vested. Using the closing market price of $35.39 per unit at December 31, 2013, the fair value of these phantom units would have been $4,503,696. There were no DERs associated with June 27, 2013 grant.

If Mr. Slifka's employment agreement had not been renewed by our general partner at the end of the applicable term, and Mr. Slifka did not continue to serve as our general partner's President and Chief Executive Officer following the expiration of the then current term of his employment agreement, Mr. Slifka would have been entitled to be paid a lump sum payment equal to 100% of his then base salary plus any Accrued Obligations. For purposes of the above table we have assumed that Mr. Slifka's employment agreement was due to be renewed as of December 31, 2013 and we used Mr. Slifka's current base salary.

(2) Andrew Slifka

The employment agreement between our general partner and Mr. Slifka provides, upon termination of his employment for any reason, that Mr. Slifka will receive payment through the date of termination of his employment of (i) any earned, but unpaid, base salary as then in effect, (ii) all earned, but unpaid, bonuses, and (iii) all accrued vacation, expense reimbursements and other benefits (other than severance benefits, except as provided below) due Mr. Slifka in accordance with the established plans and policies of our general partner or applicable law (the "Accrued Obligations").

Assuming Mr. Slifka's employment had been terminated on December 31, 2013 by our general partner for "Cause" (defined below) or by Mr. Slifka voluntarily (for reasons other than Constructive Termination), then following such termination Mr. Slifka (or his estate, if applicable) would have been entitled to the Accrued Obligations. For purposes of Mr. Slifka's employment agreement, "Cause" is defined as (i) engaging in gross negligence or willful misconduct in the performance of duties, (ii) committing an act of fraud, embezzlement or willful breach of a fiduciary duty to us including our general partner and any of our subsidiaries (including the unauthorized disclosure of any material secret, confidential and/or proprietary information, knowledge or data of the Partnership or any of its subsidiaries), (iii) being convicted of a crime involving fraud or moral turpitude or any felony, or (iv) an uncured breach of any material provision of the agreement.

Assuming Mr. Slifka's employment had been terminated on December 31, 2013 by reason of Mr. Slifka's death or "Disability" (defined below), then following such termination Mr. Slifka (or his

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estate, if applicable) would have been entitled to (i) the Accrued Obligations, and (ii) the base salary then in effect ($425,000) as well as all the fringe benefits that Mr. Slifka was receiving as of December 31, 2013 through February 28, 2015. Furthermore, if Mr. Slifka's employment is terminated due to his Disability, our general partner shall pay an amount equal to the product of 75% and the sum of (i) the base salary in effect as of December 31, 2013 ($425,000); and (ii) the average of the aggregate bonuses and short-term cash incentive amounts awarded to Mr. Slifka pursuant to the agreement, if any, since March 1, 2012.

Pursuant to Mr. Slifka's employment agreement, "Disability" is defined as a physical or mental condition which (a) renders Mr. Slifka, with or without reasonable accommodation, unable to engage in any substantial gainful activity by reason of any medically determinable physical or mental impairment which can be expected to result in death or can be expected to last for a continuous period of not less than 12 months, or (b) by reason of any medically determinable physical or mental impairment which can be expected to result in death or can be expected to last for a continuous period of not less than 12 months, results in Mr. Slifka receiving income replacement benefits for a period of not less than three months under an accident and health plan covering employees of our general partner.

Assuming Mr. Slifka's employment had been terminated on December 31, 2013 by our general partner without Cause, or by Mr. Slifka for reasons constituting "Constructive Termination" (defined below), Mr. Slifka would have been entitled to receive a lump sum payment in an amount equal to the (i) base salary and fringe benefits that would have been payable to Mr. Slifka during the balance of the agreement, (ii) the aggregate bonus and short-term cash incentive amounts awarded to Mr. Slifka, if any, since March 1, 2012, and (iii) an additional lump sum amount equal to the product of 75% and the sum of (a) the base salary as in effect on December 31, 2013 ($425,000) and (b) the average of any bonuses and short-term cash incentive amounts awarded pursuant to the agreement, if any, since March 1, 2012. In addition, Mr. Slifka would be entitled to continue to receive any fringe benefits in effect on the date of such termination through the end of the term of his employment agreement.

Mr. Slifka's employment agreement defines "Constructive Termination" as the termination of the agreement by Mr. Slifka as a result of any (i) substantial diminution, without his written consent, in Mr. Slifka's working conditions consisting of (a) a material reduction in his duties and responsibilities, (b) any change in the reporting structure so that he no longer reports solely to the President and Chief Executive Officer of our general partner, or (c) a relocation of his place of work further than 40 miles from Waltham, Massachusetts, or (ii) an uncured material breach of the agreement by our general partner. Assuming a December 31, 2012 termination date, in the event that Mr. Slifka elected to terminate his employment for constructive termination, he must provide notice to our general partner of the existence of any of the conditions set forth in the immediately preceding sentence within 90 days of the initial existence of such condition(s), and our general partner must fail to remedy such condition(s) within 30 days of such notice. In no event shall the date of termination in connection with a constructive termination occur any later than one year following the initial existence of the condition(s) constituting a constructive termination under the employment agreement.

If Mr. Slifka's employment agreement had not been renewed by our general partner at the end of the applicable term, and Mr. Slifka did not continue to serve as an Executive Vice President of our general partner or President of the Alliance Gasoline Division of the Partnership following the expiration of the employment agreement pursuant to a different employment agreement with our general partner, our general partner would have been obligated to pay Mr. Slifka in 12 equal monthly installments in amounts equal to the greater of (a) the product of 75% and the sum of (i) the base salary in effect as of the end of the agreement; and (ii) the average of the aggregate bonuses and short-term cash incentive amounts awarded to Mr. Slifka pursuant to the agreement, if any, for the two calendar years immediately preceding the expiration of the agreement; and (b) the base salary in effect as of the end of the agreement.

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(3) Daphne H. Foster

In the event of a "Change of Control" (defined below), the agreements governing the terms of the grant by the Compensation Committee on June 27, 2013 to Ms. Foster of 21,889 phantom units provide for accelerated vesting of any and all outstanding phantom units held by her as in effect on the date of termination of Ms. Foster's employment. Pursuant to such agreements, a "Change of Control" is deemed to occur on the date that any one person, entity or group (other than Richard Slifka or Eric Slifka, or their respective family members or entities they control, individually or in the aggregate, directly or indirectly) acquires ownership of the membership interests of our general partner that, together with the membership interests of our general partner already held by such person, entity or group, constitutes more than 50% of the total voting power of the membership interests of our general partner.

The change of control agreement between our general partner and Ms. Foster (the "Change of Control Agreement") provides that, upon termination of her employment (i) by our general partner "Without Cause" (defined below), (ii) by Ms. Foster for "Good Reason" (defined below), or (iii) in the case of a termination occurring during the three (3) month period ending on the Change of Control, Ms. Foster will receive payment of (a) any earned, but unpaid, base salary as then in effect, (b) all earned, but unpaid, bonuses, (c) all accrued vacation, expense reimbursements and other benefits (other than severance), and (d) any and all other amounts that as of the date of termination may be due Ms. Foster in accordance with the established plans and policies of our general partner or applicable law. "Cause" is defined in the Change of Control Agreement as having (i) engaged in gross negligence or willful misconduct in the performance of duties, (ii) committed an act of fraud, embezzlement or willful breach of fiduciary duty to our general partner or any of its subsidiaries (including the unauthorized disclosure of any material secret, confidential and/or proprietary information, knowledge or data of our general partner or any of its subsidiaries); (iii) been convicted of (or pleaded no contest to) a crime involving fraud, dishonesty or moral turpitude or any felony or (iv) any uncured breach of any material provision of the non-competition agreement between Ms. Foster and our general partner, and "Good Reason" is defined as the occurrence of any material diminution, without Ms. Foster's written consent, in Ms. Foster's working conditions consisting of (a) a material reduction in her duties and responsibilities, (b) a material change in her title, or (c) a relocation of her place of work further than forty (40) miles from Waltham, Massachusetts.

(4) Thomas J. Hollister

Mr. Hollister retired from his employment with our general partner as Chief Operating Officer and Chief Financial Officer on June 30, 2013. Prior to his retirement, Mr. Hollister entered into a Retirement, Consulting and Noncompete Agreement (the "2013 Agreement") pursuant to which Mr. Hollister (i) continued to receive his base salary through December 31, 2013, (ii) participated in our general partner's health insurance, pension, 401(k), long-term disability, life insurance 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, but (iii) was not eligible for, did not accrue, earn or participate in any Bonus or LTIP or in any Short-Term Incentive Plan. Pursuant to the 2013 Agreement, Mr. Hollister also (i) received his accrued unused vacation and (ii) commencing January 1, 2014, is entitled to receive a monthly gross amount equal to $48,166.66 for a period of eighteen months. The 2013 Agreement includes (i) a confidentiality provision which, subject to typical exceptions for requirement of law and public knowledge (other than as a result of unauthorized disclosure by Mr. Hollister), prohibits Mr. Hollister from disclosing confidential information of the Partnership or our general partner without the written consent of the Board of Directors of the Partnership or a person authorized in writing thereby, and (ii) non-competition provisions which continue for a period of two years from his last day of employment with our general partner. The 2013 Agreement was subsequently modified by a memorandum dated July 9, 2013, whereby Mr. Hollister agreed that his active participation in certain benefit plans would terminate on December 31, 2013 and he would receive an additional cash payment in the amount of $25,500 as well as up to $10,000 in reimbursement

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for the cost of purchasing life insurance, disability, long-term health care or similar like policy premiums on his behalf. The amounts reflected in the table reflect the cash and other benefits provided pursuant to the 2013 Agreement, as modified by the memorandum dated July 9, 2013.

(5) Edward J. Faneuil

The employment agreement between our general partner and Mr. Faneuil, as amended, provides that, upon termination of his employment for any reason, Mr. Faneuil will receive payment through the date of termination of his employment of (i) any earned, but unpaid, base salary as then in effect, (ii) all earned, but unpaid, bonuses, and (iii) all accrued vacation, expense reimbursements and other benefits (other than severance benefits, except as provided below) due Mr. Faneuil in accordance with the established plans and policies of our general partner or applicable law (the "Accrued Obligations").

In the event of a change in control (defined below), Mr. Faneuil's employment agreement provides for accelerated vesting on any and all outstanding Partnership options, restricted units, phantom units, unit appreciation rights and other similar rights (under the LTIP or otherwise) held by him as in effect on the date of termination. The Compensation Committee granted to Mr. Faneuil 48,501 phantom units (without DERs) on February 5, 2009, 12,125 of which vested and were paid to Mr. Faneuil in August 2009 and another 12,125 of which vested and were paid to Mr. Faneuil in February 2011. No other such options, restricted units, phantom units, unit appreciation rights and other similar rights had been granted to Mr. Faneuil as of December 31, 2012. Assuming a change of control event (as defined in the grant) had occurred on December 31, 2012, all outstanding and unvested phantom units and associated DERs that were granted to Mr. Faneuil on February 5, 2009 automatically would become fully vested. Using the closing market price of $25.35 per unit at December 31, 2011, the fair value of the February 5, 2009 awarded phantom units would have been $614,763. Pursuant to Mr. Faneuil's employment agreement, a "change in control" is deemed to occur on the date that any one person, entity or group (other than Richard Slifka or Eric Slifka, or their respective family members or entities they control, individually or in the aggregate, directly or indirectly) acquires ownership of the membership interests of our general partner that, together with the membership interests of our general partner already held by such person, entity or group, constitutes more than 50% of the total voting power of the membership interests of our general partner.

Assuming Mr. Faneuil's employment had been terminated on December 31, 2012 by (i) our general partner for "Cause" (defined below), (ii) Mr. Faneuil voluntarily (for reasons other than Constructive Termination), or (iii) reason of Mr. Faneuil's death, then following such termination Mr. Faneuil (or his estate, if applicable) would have been entitled to the Accrued Obligations. For purposes of Mr. Faneuil's employment agreement, "Cause" is defined as (1) engaging in gross negligence or willful misconduct in the performance of duties, (2) committing an act of fraud, embezzlement or willful breach of a fiduciary duty to us including our general partner and any of our subsidiaries (including the unauthorized disclosure of any material secret, confidential and/or proprietary information, knowledge or data of the Company or any of its subsidiaries), (3) being convicted of (or pleading no contest to) a crime involving fraud, dishonesty or moral turpitude or any felony, or (4) an uncured breach of any material provision of the agreement.

Assuming Mr. Faneuil's employment had been terminated on December 31, 2012 by our general partner without Cause, or by Mr. Faneuil for reasons constituting "Constructive Termination" (defined below), Mr. Faneuil would have been entitled to receive a severance payment in an amount equal to the sum of (i) twice his then base salary ($752,000), plus (ii) if such termination had occurred within 12 months following a Change in Control, an additional amount equal to twice his target incentive amount under the then applicable short-term incentive for the fiscal year ($275,000), for a total severance amount of $1,027,000. Such severance payment would be payable monthly in 24 equal installments. In addition, the general partner would provide health care continuation coverage benefits to Mr. Faneuil pursuant to the Consolidated Omnibus Budget Reconciliation Act of 1985 ("COBRA") and would continue to pay the applicable percentage of the medical insurance premium that it pays for

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active employees during the applicable COBRA coverage period. Mr. Faneuil's employment agreement defines "Constructive Termination" as the termination of employment by Mr. Faneuil as a result of (i) an uncured breach by the general partner of a material provision of the employment agreement, as amended, (ii) the failure of any successor (whether direct or indirect, by purchase, merger or otherwise) to all or substantially all of our business and/or assets to expressly assume and agree to perform the employment agreement, as amended or (iii) any material diminution, without Mr. Faneuil's written consent, in his working conditions consisting of (a) a material reduction in his duties and responsibilities as the Executive Vice President and General Counsel, (b) any change in the reporting structure so that he no longer reports to the President or Chief Executive Officer of our general partner, or (c) a relocation of his place of work further than 40 miles from Waltham, Massachusetts. For purposes of Mr. Faneuil's employment agreement, however, Constructive Termination does not include a change in reporting structure as a result of our general partner becoming a subsidiary of an unrelated entity, including, without limitation, a change whereby Mr. Faneuil is not the chief legal officer or general counsel of the acquiring or parent entity or must report to the chief legal officer or general counsel of a currently unaffiliated parent corporation or entity. Assuming a December 31, 2012 termination date, in the event Mr. Faneuil elected to terminate his employment for constructive termination at any time within three months before a change in control and 12 months after a change in control, then in addition to the foregoing severance Mr. Faneuil also would have been entitled to the accelerated vesting provisions described above.

Our general partner and Mr. Faneuil also entered into the Global Deferred Compensation Plan, pursuant to which Mr. Faneuil will be paid the sum of $70,000 per year (the "Global Deferred Compensation") in equal monthly installments of $5,833.33 on the first business day of each month for 15 years (180 months) commencing on the earlier of: (i) August 1, 2014, and (ii) the first business day of the month following Mr. Faneuil's "separation from service" (as defined in the Code) with our general partner for reasons other than "Cause" (as defined in the deferred compensation agreement), subject to earlier termination as provided in the agreement. In the event of an unforeseeable emergency as referenced in the deferred compensation agreement, our general partner will pay Mr. Faneuil within 15 days of the occurrence of the unforeseeable emergency the maximum amount allowable in a lump sum promptly following the occurrence of such unforeseeable emergency. The Global Deferred Compensation will be forfeited in its entirety in the event that our general partner terminates Mr. Faneuil's employment prior to August 1, 2014 for Cause or Mr. Faneuil terminates his employment for any reason other than death, disability or a Change in Control (as defined below). On and after the date on which Global Deferred Compensation payments commence, our general partner may terminate its obligations under the deferred compensation agreement for Cause or if our general partner subsequently determines within 18 months of Mr. Faneuil's termination that circumstances which would give rise to a for Cause termination of Mr. Faneuil otherwise existed at the time of his earlier termination. In the event of Mr. Faneuil's death prior to his receiving any or all of the aggregate amount of the Global Deferred Compensation (including in the the event of Mr. Faneuil's death before August 1, 2014), our general partner will pay Mr. Faneuil's beneficiary within 60 days of the date of his death a single lump sum payment in an amount equal to the present value of the remaining payments that would have been paid to Mr. Faneuil. If there is a Change in Control or Mr. Faneuil is determined to have become disabled prior to his receiving any or all of the aggregate amount of the Global Deferred Compensation (including if the Change of Control occurred or the determination that Mr. Faneuil became disabled were made before August 1, 2014), our general partner will pay to Mr. Faneuil within 60 days of the effective date of the Change in Control or the determination that Mr. Faneuil became disabled a single lump sum payment in an amount equal to the present value of the remaining payments that would have been paid to him had the Change in Control not occurred or had Mr. Faneuil not become disabled. For purposes of the Global Deferred Compensation Agreement, "Cause", as defined in the deferred compensation agreement, means (a) any uncured material breach by Mr. Faneuil of his obligations under the Global Deferred Compensation Agreement, (b) any breach by Mr. Faneuil of his confidentiality, non-competition and non-solicitation obligations set forth on Exhibit "A" to the Global Deferred Compensation Agreement or included in his employment

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agreement with our general partner, (c) engagement in gross negligence or willful misconduct in the performance of his duties, (d) a conviction or plea of no contest to a crime involving fraud, dishonesty or moral turpitude or any felony, or (e) the commission of an act of embezzlement or willful breach of a fiduciary duty to our general partner, the Partnership or any of its Affiliates.

Alliance and Mr. Faneuil also entered into the Alliance Deferred Compensation Agreement, the terms of which, including, without limitation, the payment terms thereunder, are on the same terms as those of the Global Deferred Compensation Agreement. Accordingly, the various scenarios involving a change of control or termination of employment under the Alliance Deferred Compensation Agreement are identical to those described above with respect to the Global Deferred Compensation Agreement.

Mr. Faneuil entered into a SERP agreement with our general partner on December 31, 2009. The value of the benefit to be provided under the SERP agreement, expressed as a single lump sum payment, is $159,355. Mr. Faneuil will acquire a fully vested and nonforfeitable interest in his SERP benefit only to the extent he is continuously employed with our general partner from December 31, 2009 through the vesting dates set forth in his SERP agreement, or if he dies or becomes Disabled (as such term is defined in the SERP agreement) after December 31, 2009 while employed with our general partner or if there is a Change in Control (as such term is defined in the SERP agreement).

Our general partner is obligated to reimburse Mr. Faneuil for any and all federal excise taxes and penalties (other than penalties imposed as a result of Mr. Faneuil's actions), and any taxes imposed upon such reimbursement amounts, including, but not limited to, any federal, state and local income taxes, employment taxes, and other taxes, if any, which may become due pursuant to the application of Sections 4999 and/or 409A of the Code on any payments to Mr. Faneuil in connection with the employment agreement, as amended. Mr. Faneuil and our general partner have agreed to reform any provision of the deferred compensation agreement, as amended, between them in a manner mutually agreeable to avoid imposition of any additional tax under the provisions of Section 409A of the Code and related regulations and Treasury pronouncements.

(6) Charles A. Rudinsky

In the event of a "Change of Control" (defined below), the agreements governing the terms of the grants by the Compensation Committee on June 27, 2013 and September 23, 2013 to Mr. Rudinsky of 5,091 and 1,273 phantom units, respectively, provide for accelerated vesting on any and all outstanding phantom units held by him as in effect on the date of termination. Pursuant to such agreements, a "Change of Control" is deemed to occur on the date that any one person, entity or group (other than Richard Slifka or Eric Slifka, or their respective family members or entities they control, individually or in the aggregate, directly or indirectly) acquires ownership of the membership interests of our general partner that, together with the membership interests of our general partner already held by such person, entity or group, constitutes more than 50% of the total voting power of the membership interests of our general partner.

The change of control agreement between our general partner and Mr. Rudinsky (the "Change of Control Agreement") provides that, upon termination of his employment (i) by our general partner "Without Cause" (defined below), (ii) by Mr. Rudinsky for "Good Reason" (defined below), or (iii) in the case of a termination occurring during the three (3) month period ending on the Change of Control, Mr. Rudinsky will receive payment of (a) any earned, but unpaid, base salary as then in effect, (b) all earned, but unpaid, bonuses, (c) all accrued vacation, expense reimbursements and other benefits (other than severance), and (d) any and all other amounts that as of the date of termination may be due Mr. Rudinsky in accordance with the established plans and policies of our general partner or applicable law. "Cause" is defined in the Change of Control Agreement as having (i) engaged in gross negligence or willful misconduct in the performance of duties, (ii) committed an act of fraud, embezzlement or willful breach of fiduciary duty to our general partner or any of its subsidiaries (including the unauthorized disclosure of any material secret, confidential and/or proprietary

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information, knowledge or data of our general partner or any of its subsidiaries); (iii) been convicted of (or pleaded no contest to) a crime involving fraud, dishonesty or moral turpitude or any felony or (iv) any uncured breach of any material provision of the non-competition agreement between Mr. Rudinsky and our general partner, and "Good Reason" is defined as the occurrence of any material diminution, without Mr. Rudinsky's written consent, in Mr. Rudinsky working conditions consisting of (a) a material reduction in his duties and responsibilities, (b) a material change in his title, or (c) a relocation of his place of work further than forty (40) miles from Waltham, Massachusetts.

(7) Mark A. Romaine

In the event of a "Change of Control" (defined below), the agreements governing the terms of the grant by the Compensation Committee on June 27, 2013 to Mr. Romaine of 57,023 phantom units provide for accelerated vesting of any and all outstanding phantom units held by him as in effect on the date of termination of Mr. Romaine's employment. Pursuant to such agreements, a "Change of Control" is deemed to occur on the date that any one person, entity or group (other than Richard Slifka or Eric Slifka, or their respective family members or entities they control, individually or in the aggregate, directly or indirectly) acquires ownership of the membership interests of our general partner that, together with the membership interests of our general partner already held by such person, entity or group, constitutes more than 50% of the total voting power of the membership interests of our general partner.

The change of control agreement between our general partner and Mr. Romaine (the "Change of Control Agreement") provides that, upon termination of his employment (i) by our general partner "Without Cause" (defined below), (ii) by Mr. Romaine for "Good Reason" (defined below), or (iii) in the case of a termination occurring during the three (3) month period ending on the Change of Control, Mr. Romaine will receive payment of (a) any earned, but unpaid, base salary as then in effect, (b) all earned, but unpaid, bonuses, (c) all accrued vacation, expense reimbursements and other benefits (other than severance), and (d) any and all other amounts that as of the date of termination may be due Mr. Romaine in accordance with the established plans and policies of our general partner or applicable law. "Cause" is defined in the Change of Control Agreement as having (i) engaged in gross negligence or willful misconduct in the performance of duties, (ii) committed an act of fraud, embezzlement or willful breach of fiduciary duty to our general partner or any of its subsidiaries (including the unauthorized disclosure of any material secret, confidential and/or proprietary information, knowledge or data of our general partner or any of its subsidiaries); (iii) been convicted of (or pleaded no contest to) a crime involving fraud, dishonesty or moral turpitude or any felony or (iv) any uncured breach of any material provision of the non-competition agreement between Mr. Romaine and our general partner, and "Good Reason" is defined as the occurrence of any material diminution, without Mr. Romaine's written consent, in Mr. Romaines's working conditions consisting of (a) a material reduction in his duties and responsibilities, (b) a material change in his title, or (c) a relocation of his place of work further than forty (40) miles from Waltham, Massachusetts. Assuming Mr. Romaine's employment was terminated on December 31, 2013, those unpaid portions of his deferred bonuses earned in 2010, 2011 and 2012 would have been accelerated and become fully due and payable upon termination.

(8) LTIP Awards

On June 27, 2013, the Compensation Committee made grants of 127,259, 76,356, 57,012, 29,537, 21,889 and 5,091 phantom units under the LTIP, respectively, to Messrs. Eric Slifka, Faneuil, Romaine and Andrew Slifka, Ms. Foster and Mr. Rudinsky. On September 23, 2013, the Compensation Committee made a grant of 1,273 phantom units under the LTIP to Mr. Rudinsky. Upon a change of control event, all outstanding phantom units that were granted in 2013 to Messrs. Eric Slifka, Faneuil, Romaine and Andrew Slifka, Ms. Foster and Mr. Rudinsky and that have not otherwise vested automatically will become fully vested. See "Elements of Compensation—Long-Term Incentive Plan" for information regarding performance restrictions and additional vesting terms.

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Other Benefits

Pension Benefits

The table below sets forth information regarding the present value as of December 31, 2013 of the accumulated benefits of our named executive officers under the Global Partners LP Pension Plan, Supplemental Executive Retirement Agreements and, with respect to Mr. Faneuil, the Global and Alliance Deferred Compensation Agreements. Amounts with respect to the Global and Alliance Deferred Compensation Plans are reflected in the table below because they represent a fixed entitlement.

Pension Benefits at December 31, 2013

Name			Number of Years Credited Service		Present Value of Accumulated Benefit		Payments During Last Fiscal Year

			(#)		($)		($)
Eric Slifka	(1	)		24		419,998		—
Andrew P. Slifka	(1	)		7		19,806		—
Andrew P. Slifka	(2	)		12		173,530		—
Thomas J. Hollister	(1	)		5		106,627		—
Daphne H. Foster	(1	)		3		30,106		—
Edward J. Faneuil	(1	)		20		545,672		—
Edward J. Faneuil	(3	)		n/a		127,484		—
Edward J. Faneuil	(4	)		n/a		845,908		—
Edward J. Faneuil	(5	)		n/a		845,908		—
Charles A. Rudinsky (6)	(1	)		27		906,168		51,657
Mark A. Romaine	(1	)		11		149,630		—

(1): Global Partners LP Pension Plan
(2): Global Montello Group Corp. Pension Plan
(3): Supplemental Executive Retirement Agreement
(4): Global Deferred Compensation Agreement
(5): Alliance Deferred Compensation Agreement
(6): From 1984 through 1988, Mr. Rudinsky was employed by National Petroleum Corporation, Inc. In 1988, a predecessor of ours acquired all of the outstanding capital stock of National Petroleum Corporation, Inc. and Mr. Rudinsky became an employee of said predecessor of ours. In connection with this acquisition, and for purposes of the Global Partners LP Pension Plan, Mr. Rudinsky was credited with four additional years of service for the period from 1984 through 1988.

Global Partners LP Pension Plan

Effective December 31, 2009, the Global Partners LP Pension Plan (the "Global Pension Plan") was amended to freeze participation in and benefit accruals under the Global Pension Plan. Prior to the freeze, all employees who (1) were 21 years of age or older, (2) were not covered by a collective bargaining agreement providing for union pension benefits, and (3) had been employed by our predecessor, our general partner or one of our operating subsidiaries for one year prior to enrollment in the Global Pension Plan were eligible to participate in the Global Pension Plan. An employee is fully vested in benefits under the Global Pension Plan after completing five years of service or 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 on each December 31 beginning in 2010 and lasting through 2014. When an employee retires at age 65, the employee can elect to receive a monthly annuity or an equivalent lump sum payment. An employee's benefit payable at retirement is equal to (1) 23% of the employee's average monthly compensation for the five consecutive calendar years during which the employee received the highest amount of pay ("Average Compensation") plus (2) 19.5% of the employee's Average Compensation in excess of his monthly "covered compensation" for Social Security purposes, as provided in the Global Pension Plan. However, if an employee has completed less than 30 years of service on his termination at or after reaching age 65, the monthly benefit will be reduced by 1/30th for each year less than 30 years completed by the employee. When an employee retires at an age other than 65, the employee retirement benefit will be the actuarial equivalent of the benefit he or she would have received if he or she had retired at age 65. An employee who terminates employment after completing at least five years of service will be eligible for an early retirement benefit determined as described in the preceding sentence at any time after attaining age 60.

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Benefits under the formula are based upon the employee's highest consecutive five-year average compensation and are not subject to offset for social security benefits. Compensation for such purposes means compensation including overtime, but excluding bonuses, 50% of commissions, taxable fringe benefits, relocation allowances, transportation allowances, housing allowances, cash and DERs pursuant to any long-term incentive plan and any cash payable in lieu of group healthcare coverage. These estimated annual pension benefits do not include supplemental benefits, if any, to which the employee may be entitled.

GMG Pension Plan

As a result of the Alliance Acquisition, effective as of March 1, 2012, sponsorship of Alliance Energy LLC Pension 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. Pension Plan (the "GMG Pension Plan"). Effective May 15, 2012, the GMG Pension Plan was amended to freeze participation in and benefit accruals. Prior to the freeze, all employees who (1) were 21 years of age or older, (2) were not covered by a collective bargaining agreement providing for union pension benefits, (3) had been employed by GMG or a predecessor employer for one year prior to enrollment in the Pension Plan, (4) were not nonresident aliens, (5) had not become employees as a result of Code Section 410(b)(6)(C) transaction and (6) were not non-exempt gas station/c-store employees hired on or after January 1, 2007 or employees hired after September 30, 2009 were eligible to participate in the GMG Pension Plan. An employee is fully vested in benefits under the GMG Pension Plan after completing five years of service or, if earlier, upon termination due to death, disability or retirement. When an employee retires at age 65 with 5 years of service, the employee can elect to receive a monthly annuity or an equivalent lump sum payment. The employee's benefit payable at retirement is equal to (1) 23% of the employee's average monthly compensation for the five consecutive calendar years during which the employee received the highest amount of pay ("Average Compensation") plus (2) 19.5% of the employee's Average Compensation in excess of his monthly "covered compensation" for Social Security purposes, as provided in the GMG Pension Plan. When an employee retires at an age other than 65, the employee retirement benefit will be the actuarial equivalent of the benefit he or she would have received if he or she had retired at age 65. An employee who terminates employment after completing at least five years of service will be eligible for an early retirement benefit determined as described in the preceding sentence at any time after attaining age 60.

Benefits under the GMG Pension Plan formula are based upon the employee's highest consecutive five-year average compensation and are not subject to offset for social security benefits. Compensation for such purposes means compensation including overtime, but excluding bonuses, 50% of commissions, deferred compensation, employee benefits, moving expenses, transportation allowance, salary continuation and non-cash remuneration.

Supplemental Executive Retirement Agreement

For a description of the benefits provided to Mr. Faneuil pursuant to his SERP Agreement, please see "Employment and Related Agreements—Supplemental Executive Retirement Agreement."

Global and Alliance Deferred Compensation Agreements

For a description of the deferred compensation arrangements provided to Mr. Faneuil pursuant to the Global Deferred Compensation Plan and the Alliance Deferred Compensation Plan, please see "Employment and Related Agreements—Deferred Compensation Agreements" and "Potential Payments upon a Change of Control or Termination"

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Compensation of Directors

The following table sets forth (i) certain information concerning the compensation earned by our directors in 2013, and (ii) the aggregate amounts of stock awards and option awards, if any, held by each director at the end of the last fiscal year:

			Equity Incentive Plan Awards

Name	Fees Earned or Paid in Cash ($)		Grant Date Fair Value of Unit Awards ($) (2)		Total ($)
Alfred Slifka		70,000		—		70,000
Richard Slifka		70,000		—		70,000
Eric Slifka (1)		—		—		—
Andrew Slifka (1)		—		—		—
Kenneth I. Watchmaker		97,500		320,000		417,500
Robert J. McCool		90,000		320,000		410,000
David McKown		88,000		320,000		408,000

(1): Messrs. Eric Slifka and Andrew Slifka, as executive officers of our general partner, are otherwise compensated for their services and therefore receive no separate compensation for their service as directors.
(2): All of the equity grant awards shown in the table were made under the Global Partners LP Long-Term Incentive Plan ("LTIP"). No awards had been previously made to the independent directors under the LTIP since 2010; the awards shown in the table above represent additional director compensation for 2013 and 2014. Amounts disclosed in the table reflect the full grant date fair value of Partnership phantom units granted on June 27, 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 director for the invested award), or that the value upon vesting will approximate the aggregate grant date fair value determined under ASC Topic 718. As of December 31, 2013 our non-employee directors held the following number of phantom units, each of which 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: Mr. Watchmaker (8,145), Mr. McCool (8,145) and Mr. McKown (8,145).

Employees of our general partner who also serve as directors do not receive additional compensation. In 2013, directors who are not employees of our general partner (1) received: (a) $60,000 annual cash retainer; (b) $1,000 for each meeting of the board of directors attended; (c) $2,000 for each audit committee meeting attended (limited to payment for one committee meeting per day); and (d) $1,000 for each committee meeting other than the audit committee meeting attended (limited to payment for one committee meeting per day), and (2) are eligible to participate in the LTIP. In 2013, the chair of the audit committee received an additional $7,500.

Each director also is reimbursed for out-of-pocket expenses in connection with attending meetings of the board of directors or committees.

On June 27, 2013, each of our non-employee independent directors received an award of 8,145 phantom units. These phantom units vest over a three 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.

Each director will be fully indemnified by us for actions associated with being a director to the extent permitted under Delaware law.

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Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

The following table sets forth as of March 28, 2014 the beneficial ownership of units of Global Partners LP held by certain beneficial owners of more than 5% of the units, by each director and named executive officer of our general partner and by all directors and executive officers of our general partner as a group:

Name of Beneficial Owner(1)

AE Holdings Corp. (2)	5,850,000	21.3	%
Kayne Anderson Capital Advisors L.P. (3)	3,789,084	13.8	%
Richard A. Kayne (3)	3,789,084	13.8	%
OppenheimerFunds Inc. (4)	2,988,386	10.9	%
Montello Oil Corporation (5)	2,348,078	8.6	%
Global Petroleum Corp. (6)	1,725,463	6.3	%
Oppenheimer Steelpath MLP Income Fund (4)	1,538,182	5.6	%
Larea Holdings LLC (7)	564,984	2.1	%
Larea Holdings II LLC (8)	282,492	1.0	%
Chelsea Terminal Limited Partnership (9)	120,356	*
Global GP LLC (10)	169,816	*
Sandwich Terminal, L.L.C. (11)	8,475	*
Alfred A. Slifka (2)(5)(6)(9)(10)(11)(12)**	10,272,298	37.4	%
Richard Slifka (2)(5)(6)(8)(9)(10)(11)(12)	10,554,687	38.5	%
Eric Slifka (7)(13)	754,500	2.7	%
Andrew Slifka (8)	89,131	*
Edward J. Faneuil	50,157	*
Thomas J. Hollister	40,084	*
Charles A. Rudinsky	19,721	*
Mark Romaine	18,115	*
Daphne H. Foster	400	*
Robert J. McCool	11,227	*
Kenneth I. Watchmaker	8,777	*
David K. McKown	2,427	*
All directors and executive officers as a group (12 persons)	11,599,336	42.3	%

*: Less than 1%
**: Alfred A. Slifka, former chairman of the board of our general partner, passed away on March 9, 2014. Mr. Slifka's estate is in probate and his beneficially owned interests in Global Partners LP and its affiliates have not yet been settled.
(1): The address for each person or entity listed other than (i) Kayne Anderson Capital Advisors, L.P., (ii) Richard A. Kayne, (iii) OppenheimerFunds, Inc., and (iv) Oppenheimer Steelpath MLP Income Fund is P.O. Box 9161, 800 South Street, Suite 200, Waltham, Massachusetts 02454-9161.
(2): AE Holdings Corp. owns 5,850,000, or 21.3%, of the common units of Global Partners LP. Alfred A. Slifka and Richard Slifka share voting and investment power with respect to and, therefore, may be deemed to beneficially own the units owned by AE Holdings Corp.
(3): According to a Schedule 13G/A filed on February 13, 2014, Kayne Anderson Capital Advisors, L.P. and Richard A. Kayne beneficially owned 3,789,084 common units, representing 13.81% of the common units then outstanding. The address for Kayne Anderson Capital Advisors, L.P. and Richard A. Kayne is 1800 Avenue of the Stars, Third Floor, Los Angeles, California 90067.

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(4): According to a Schedule 13G filed on July 10, 2013, OppenheimerFunds, Inc. beneficially owned 2,988,386 common units, representing 10.89% of the common units then outstanding and Oppenheimer Steelpath MLP Income Fund beneficially owned 1,538,182 common units, representing 5.6% of the common units then outstanding. The address for OppenheimerFunds, Inc. is Two World Financial Center, 225 Liberty Street, New York, NY 10281 and the address for Oppenheimer Steelpath MLP Income Fund is 2100 McKinney Ave, Suite 1401, Dallas, TX 75201.
(5): Alfred A. Slifka and Richard Slifka share voting and investment power with respect to and, therefore, may be deemed to beneficially own, the units owned by Montello Oil Corporation.
(6): Alfred A. Slifka and Richard Slifka share voting and investment power with respect to, and therefore may be deemed to beneficially own, the units owned by Global Petroleum Corp.
(7): Eric Slifka has sole voting and investment power with respect to units owned by Larea Holdings LLC. Eric Slifka may, therefore, be deemed to beneficially own the units held by Larea Holdings LLC. Eric Slifka is the son of Alfred A. Slifka.
(8): Richard Slifka is the trustee of a voting trust with sole voting and investment power with respect to units owned by Larea Holdings II LLC. Richard Slifka may, therefore, be deemed to beneficially own the units held by Larea Holdings II LLC. Richard Slifka's son, Andrew Slifka, is a one-third owner of Larea Holdings II LLC. Because Andrew Slifka does not share voting and investment power with respect to the units owned by Larea Holdings II LLC, he is not deemed to beneficially own such units.
(9): Alfred A. Slifka and Richard Slifka share voting and investment power with respect to and, therefore, may be deemed to beneficially own, the units owned by Chelsea Terminal Limited Partnership.
(10): Purchased by our general partner for the purpose of assisting us in meeting our anticipated obligations to deliver common units under our Long-Term Incentive Plan to officers, directors and employees, and meeting obligations under existing employment agreements with the officers of our general partner. Alfred A. Slifka and Richard Slifka control Global GP LLC, and thus may be deemed to beneficially own the units owned by Global GP LLC.
(11): Alfred A. Slifka and Richard Slifka are equal owners of Sandwich Terminal, L.L.C. and share voting and investment power with respect to and, therefore, may be deemed to beneficially own, the units owned by Sandwich Terminal, L.L.C.
(12): Beneficially owned unit amounts for each of Alfred A. Slifka and Richard Slifka include the units owned by AE Holdings Corp., Montello Oil Corporation, Global Petroleum Corp., Chelsea Terminal Limited Partnership, Global GP LLC and Sandwich Terminal, L.L.C. Beneficially owned unit amounts for Richard Slifka also include the units owned by Larea Holdings II LLC and the units owned by the Rosalyn and Richard Slifka Charitable Trust, of which Richard Slifka is a trustee. Alfred A. Slifka and Richard Slifka are brothers.
(13): Beneficially owned unit amounts for Eric Slifka include the units owned by Larea Holdings LLC.

Equity Compensation Plan Table

The following table summarizes information about our equity compensation plans as of December 31, 2013:

Plan Category	Number of Securities to be issued upon exercise of outstanding options, warrants and rights		Weighted average exercise price of outstanding options, warrants and rights		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))

	(a)		(b)		(c)
Equity compensation plans approved by security holders		498,111		—		3,801,889
Equity compensation plans not approved by security holders		—		—		—


Total		498,111		—		3,801,889

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Item 13. Certain Relationships and Related Transactions, and Director Independence.

As of March 28, 2014, affiliates of our general partner, including directors and executive officers of our general partner, owned 11,599,336 common units representing 42.3% of the limited partner interests in us. In addition, our general partner owns a 0.83% general partner interest in us.

Distributions and Payments to Our General Partner and Its Affiliates

The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with the ongoing operation and liquidation of Global Partners LP pursuant to our partnership agreement. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm's-length negotiations.

Operational Stage


Distributions of available cash to our general partner and its affiliates		We will generally make cash distributions of 99.17% to the unitholders, including affiliates of our general partner (including directors and executive officers of our general partner), as the holders of an aggregate of 11,599,336 common units and 0.83% to our general partner. In addition, if distributions exceed the minimum quarterly distribution and other higher target levels, our general partner will be entitled to increasing percentages of the distributions, up to 48.83% of the distributions above the highest target level.
		Assuming we have sufficient available cash to pay the full minimum quarterly distribution on all of our outstanding units for four quarters, our general partner and its affiliates, including directors and executive officers of our general partner, would receive an annual distribution of approximately $0.4 million on the 0.83% general partner interest and $21.5 million on their common units.
Payments to our general partner and its affiliates		Our general partner does not receive a 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. Our partnership agreement provides that our general partner determines the amount of these expenses.
Withdrawal or removal of our general partner		If our general partner withdraws or is removed, its general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests.

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

Omnibus Agreement

We are a party to an omnibus agreement with certain members of the Slifka family and our general partner that addresses the agreement of certain members of the Slifka family not to compete with us and to cause their affiliates not to compete with us under certain circumstances. The omnibus agreement also addressed certain environmental indemnity obligations of Global Petroleum Corp. and certain of its affiliates, which indemnity obligations have expired. In connection with our acquisition of Alliance Energy LLC, each of Alfred A. Slifka, former Chairman of our general partner, and Richard Slifka, Chairman of our general partner, entered into a business opportunity agreement with our general partner containing noncompetition provisions which are broader than those contained in the omnibus agreement in order to encompass our expanded lines of business since 2005.

Noncompetition

Pursuant to the omnibus agreement and the business opportunity agreement each of Alfred A. Slifka, and Richard Slifka agreed, and pursuant to his employment agreement with our general partner each of Eric Slifka and Andrew Slifka agreed, for themselves and their respective affiliates, not to engage in, acquire or invest in any of the following businesses: (1) the wholesale and/or retail marketing, sale, distribution and transportation (other than transportation by truck) of refined petroleum products, crude oil, natural gas, ethanol, propane and/or biofuels; (2) the storage of refined petroleum products, crude oil, natural gas, ethanol, propane, biofuels and/or asphalt or asphalt products in connection with any of the activities described in (1); and (3) such other businesses in which we are engaged or, to their individual knowledge, we have commenced efforts to become engaged. Pursuant to the omnibus agreement, each of Alfred A. Slifka's and Richard Slifka's noncompetition obligations survive for so long as Alfred A. Slifka, Richard Slifka, Eric Slifka and/or any of their respective affiliates, individually or as part of a group, control our general partner. Pursuant to each of Eric Slifka's and Andrew Slifka's employment agreements with our general partner, their noncompetition obligations survive for one year following the termination of each of their employment.

In addition, Eric Slifka's and Andrew Slifka's employment agreements include, and Eric Slifka and Andrew Slifka both agreed to, a confidentiality provision and a nonsolicitation provision, which generally will continue for two years and for one year, respectively, following Eric Slifka's and Andrew Slifka's termination of employment.

Shared Services Agreements

We are party to a shared services agreement with Global Petroleum Corp. and, until March 2012 we were party to a shared services agreement with Alliance Energy LLC. We believe the terms of these agreements are or were at least as favorable as could have been obtained from unaffiliated third parties. Under these agreements, we provide Global Petroleum Corp. and we provided Alliance Energy LLC with certain accounting, treasury, legal, information technology, human resources and financial operations support for which Global Petroleum Corp. and Alliance Energy LLC, as applicable, pay or paid us an amount based upon the cost associated with the provision of such services. In addition, Global Petroleum Corp. provides us with certain terminal, environmental and operational support services, for which we pay a fee based on an agreed assessment of the cost associated with provision of such services. Through March 1, 2012, when we acquired all of the membership interests in Alliance Energy LLC, Alliance Energy LLC also provided us with certain support services for which we paid a fee based on an agreed assessment of the cost associated with the provision of such services.

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With respect to the shared services agreements, we paid to Global Petroleum Corp. a total of $96,000 for each of the years ended December 31, 2013, 2012 and 2011 and received from Alliance Energy LLC a total of $0, $31,000 and $187,000 for the years ended December 31, 2013, 2012 and 2011, respectively. The agreement with Global Petroleum Corp. is for an indefinite term, and either party may terminate its receipt of some or all of the services thereunder upon 180 days' notice at any time after January 1, 2009. As of December 31, 2013, no such notice of termination was given by either party.

In March 2012, following the closing of our acquisition of all of the membership interests in Alliance Energy LLC, (a) our shared services agreement with Alliance Energy LLC was terminated, (b) our shared services agreement with Global Petroleum Corp. was amended to include the services provided by Global Petroleum Corp. to Alliance Energy LLC, and (c) we entered into a shared services agreement with AE Holdings Corp. pursuant to which we provide AE Holdings Corp. with certain tax, accounting, treasury and legal support services for which AE Holdings Corp. pays us $15,000 per year. We believe the terms of the AE Holdings Corp. agreement is at least as favorable as could have been obtained from unaffiliated third parties. The agreement with AE Holdings Corp. is for an indefinite term and AE Holdings Corp. may terminate its receipt of some or all of the services upon 180 days' notice.

Management Agreements

In connection with the acquisition of retail gasoline stations and supply rights (collectively, the "Facilities") from ExxonMobil in 2010, Global Companies LLC and Global Montello Group Corp. were parties to facilities management agreements with Alliance Energy LLC. We believe the terms of these agreements were at least as favorable as could have been obtained from unaffiliated third parties. In March 2012, following the closing of our acquisition of Alliance Energy LLC, the management agreements were terminated.

Pursuant to the management agreements, Alliance Energy LLC supervised and directed the day-to-day management and operations of the Facilities for an aggregate annual management fee of $2.6 million, commencing October 1, 2010. Global Companies LLC and Global Montello Group Corp. shared in paying the annual management fees consistent with their ownership of the assets acquired pursuant to the purchase agreement. Alliance Energy LLC managed the operations of the Facilities in accordance with annual budgets approved by Global Companies LLC and Global Montello Group Corp., respectively. Global Companies LLC and Global Montello Group Corp. were responsible for the salaries of the employees directly employed to manage and operate the Facilities and for a portion of the salaries of certain administrative personnel of Alliance Energy LLC as approved by Global Companies LLC and/or Global Montello Group Corp. in accordance with the management agreements and the approved annual budgets. All matters pertaining to the employment, supervision, compensation, promotion, and discharge of such employees were the responsibility of Alliance Energy LLC. Pursuant to the management agreements, Alliance Energy LLC was required to indemnify Global Companies LLC and Global Montello Group Corp. from and against any and all claims and damages of any nature whatsoever arising out of or incidental to Alliance Energy LLC's performance of its responsibilities under the management agreements caused by or due to fraud, gross negligence, willful misconduct or a material breach by Alliance Energy LLC of any provision of the management agreements. Alliance Energy LLC's aggregate liability was capped at $5.0 million, over and above the utilization of any and all insurance proceeds. Collectively, Global Companies LLC and Global Montello Group Corp. paid to Alliance Energy LLC a total management fee and overhead reimbursement of $0.7 million and $4.2 million, respectively, for the years ended December 31, 2012 and 2011, respectively.

Sub-Jobber Agreements

We are parties to an Amended and Restated Distributor PMPA Franchise Agreement (the "Franchise Agreement") with Alliance Energy LLC. Pursuant to the Franchise Agreement, Alliance Energy LLC purchases all of its Mobil-branded fuel in Massachusetts, New Hampshire, Rhode Island

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and Maine from Global Companies LLC for a term of seven years. The price for fuel purchased under the Franchise Agreement is Global Companies LLC's distributor rack price for Mobil-branded fuels as is in effect at the time of purchase. Pursuant to the Franchise Agreement, Alliance Energy LLC is granted the right to continue using the Mobil and Exxon names and trade dress (collectively, the "Mobil Flag") at its Mobil-branded and Exxon-branded stations in Massachusetts, New Hampshire, Rhode Island and Maine.

We are party to a Volume Incentive Program Agreement with Alliance Energy LLC pursuant to which Alliance Energy LLC receives a per gallon rebate on all Mobil-branded and Exxon-branded fuel purchased from Global Companies LLC.

We believe the terms of the Franchise Agreement and the Volume Incentive Program Agreement are at least as favorable as could have been obtained from unaffiliated third parties.

Throughput Agreement with Global Petroleum Corp.

We have an exclusive throughput agreement with Global Petroleum Corp. with respect to the Revere terminal in Revere, Massachusetts. We believe the terms of this agreement are at least as favorable as could have been obtained from unaffiliated third parties. We retain the title to all our products stored at this terminal. The term of this agreement ends July 31, 2015. The agreement automatically renews annually unless it is terminated by either party by giving 90 days' notice. We pay a monthly fee to Global Petroleum Corp., which is adjusted according to the Consumer Price Index for the Northeast region and for certain contractual costs. Including increases in certain contractual costs but excluding amortization of deferred rent, we paid to Global Petroleum Corp. a total of $9.1 million, $8.9 million and $8.7 million for the years ended December 31, 2013, 2012 and 2011, respectively. Throughout the term of the throughput agreement with Global Petroleum Corp., we will have a right of first refusal through September 30, 2014 to purchase or lease the Revere terminal if Global Petroleum Corp. desires to sell or lease the Revere terminal to a third party.

Relationship of Management with Global Petroleum Corp., AE Holdings Corp. and Alliance Energy LLC

Some members of our management team are also officers and/or directors of our affiliate, Global Petroleum Corp. Global Petroleum Corp. is wholly owned by ASRS Global General Partnership, an entity that is owned equally by Richard Slifka and by the estate of Alfred A. Slifka. Messrs. Faneuil and Rudinsky spend a portion of their time providing services to Global Petroleum Corp. under a shared services agreement. Please read "—Shared Services Agreements."

Prior to the closing of our acquisition of Alliance Energy LLC, Alliance Energy LLC was wholly owned by AE Holdings Corp., which is 100% owned by members of the Slifka family. Under a shared services agreement, Messrs. Eric Slifka, Faneuil and Rudinsky also spent a portion of their time providing services to Alliance Energy LLC. Under a new shared services agreement, Messrs. Eric Slifka, Faneuil and Rudinsky spend a portion of their time providing services to AE Holdings Corp. The estate of Alfred A. Slifka and Richard Slifka share voting and investment power with respect to AE Holdings Corp. and therefore may be deemed to beneficially own the units owned by AE Holdings Corp. Please read "—Shared Services Agreements."

Prior to the acquisition of Alliance Energy LLC, we sold refined petroleum products and renewable fuels to Alliance Energy LLC at prevailing market prices at the time of delivery. Sales to Alliance Energy LLC were approximately $40.6 million and $187.1 million for the years ended December 31, 2012 and 2011, respectively. Sales for the years ended December 31, 2012 and 2011 include sales of Mobil-branded fuel to Alliance Energy LLC pursuant to the Franchise Agreement with Alliance Energy LLC, net of rebates under the Volume Incentive Program Agreement. Please read "—Sub-Jobber Agreements."

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Policies Relating to Conflicts of Interest

Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates, on the one hand, and us and our unaffiliated limited partners, on the other hand. The directors and officers of our general partner have fiduciary duties to manage our general partner in a manner beneficial to its owners. At the same time, our general partner has a fiduciary duty to manage us in a manner beneficial to our unitholders and us. Our partnership agreement modifies and limits our general partner's fiduciary duties to unitholders. Our partnership agreement also restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under applicable Delaware law. The Delaware Revised Uniform Limited Partnership Act provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties otherwise owed by a general partner to limited partners and the partnership.

Under our partnership agreement, whenever a conflict arises between our general partner or its affiliates, on the one hand, and us or any other partner, on the other, our general partner will resolve that conflict. Our general partner will not be in breach of its obligations under our partnership agreement or its duties to us or our unitholders if the resolution of the conflict is:

•: approved by the conflicts committee of our general partner, although our general partner is not obligated to seek such approval;
•: approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates;
•: on terms no less favorable to us than those generally being provided to or available from unaffiliated third parties; or
•: fair and reasonable to us, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us.

Our general partner may, but is not required to, seek the approval of such resolution from the conflicts committee of the board of directors of our general partner. If our general partner does not seek approval from the conflicts committee and its board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third and fourth bullet points above, then it will be presumed that, in making its decision, the board acted in good faith, and in any proceeding brought by or on behalf of us or any limited partner of ours, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict is specifically provided for in our partnership agreement, our general partner or the conflicts committee may consider any factors it determines in good faith to consider when resolving a conflict. When our partnership agreement requires someone to act in good faith, it requires that person to reasonably believe that he is acting in the best interests of the partnership, unless the context otherwise requires.

Director Independence

Please see Item 10, "Directors, Executive Officers and Corporate Governance" for information regarding director independence.

Item 14. Principal Accounting Fees and Services.

The audit committee of the board of directors of Global GP LLC selected Ernst & Young LLP, Independent Registered Public Accounting Firm, to audit the books, records and accounts of Global Partners LP for the 2013 and 2012 calendar years. The audit committee's charter, which is available on our website at www.globalp.com, requires the audit committee to approve in advance all audit and

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non-audit services to be provided by our independent registered public accounting firm. All services reported in the audit, audit-related, tax and all other fees categories below were approved by the audit committee.

Fees paid to Ernst & Young LLP were as follows (in thousands):

	2013		2012

Audit Fees (1)	$	3,154	$	2,740
Audit-Related Fees		150		32
Tax Fees (2)		1,771		916


Total	$	5,075	$	3,688

(1): Represents fees for professional services provided primarily in connection with the audits of our annual financial statements and reviews of our quarterly financial statements. Audit fees also included Ernst & Young's audits of the effectiveness of our internal control over financial reporting at December 31, 2013 and 2012. Fees for 2013 included an audit performed as part of the S-3 filing. Fees for 2012 included audits performed as part of the S-3 and S-8 filings and audits performed in connection with our acquisitions.
(2): Tax fees included tax planning and tax return preparation.

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PART IV

Item 15. Exhibits and Financial Statement Schedules.

(a)

The following documents are included with the filing of this report:

1.: Financial statements

See "Index to Financial Statements" on page F-1.

2.: Financial statement schedules:

Schedule II—Valuation and Qualifying Accounts

All other schedules for which provision is made in the applicable accounting regulation of the Securities and Exchange Commission are not required under the related instructions or are inapplicable and, therefore, have been omitted.

3.: Exhibits

See "Exhibit Index" immediately following the financial statement schedules in this Annual Report on Form 10-K for a description of the documents that are filed as Exhibits to this report or incorporated herein by reference.

(b): The following documents are filed as Exhibits to this report:

			Description

2.1	**	—	Contribution Agreement dated November 21, 2011, by and among Global Partners LP and AE Holdings Corp. (incorporated herein by reference to Exhibit 2.1 to the Current Report on Form 8-K filed on November 23, 2011).
2.2		—	Exhibit A to Contribution Agreement (Exhibit 2.1), Determination of the Cash Adjustment (incorporated herein by reference to Exhibit 2.2 to the Current Report on Form 8-K filed on November 23, 2011).
2.3	**	—	Membership Interest Purchase Agreement, dated as of January 22, 2013, between JH Kelly Holdings LLC and Global Partners LP (incorporated herein by reference to Exhibit 2.1 to the Current Report on Form 8-K filed on February 22, 2013).
3.1		—	Third Amended and Restated Agreement of Limited Partnership of Global Partners LP dated as of December 9, 2009 (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K filed on December 15, 2009).
4.1		—	Registration Rights Agreement, dated May 9, 2007, by and between Global Partners LP and the purchasers named therein (incorporated herein by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on May 10, 2007).
4.2		—	Registration Rights Agreement, dated March 1, 2012, by and among Global Partners LP and AE Holdings Corp. (incorporated herein by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on March 7, 2012).
4.3		—	Indenture, dated as of February 14, 2013, by and among Global Partners LP and GLP Finance Corp., as Issuers, the Guarantors party thereto and FS Energy and Power Fund, as Purchaser (incorporated herein by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on February 21, 2013).
4.4		—	Indenture, dated as of December 23, 2013, by and among Global Partners LP and GLP Finance Corp., as Issuers, the Guarantors party thereto and 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 (incorporated herein by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on December 26, 2013).

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			Description

4.5		—	Second Supplemental Indenture, dated as of December 20, 2013, by and among Global Partners LP, GLP Finance Corp., as Issuers, the Guarantors party thereto and FS Energy and Power Fund, as Purchaser (incorporated herein by reference to Exhibit 4.2 to the Current Report on Form 8-K filed on December 26, 2013).
10.1		—	Omnibus Agreement, dated October 4, 2005, by and among Global Petroleum Corp., Montello Oil Corporation, Global Revco Dock, L.L.C., Global Revco Terminal, L.L.C., Global South Terminal, L.L.C., Sandwich Terminal, L.L.C., Chelsea Terminal Limited Partnership, Global GP LLC, Global Partners LP, Global Operating LLC, Alfred A. Slifka, Richard Slifka and Eric Slifka (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on October 11, 2005).
10.2		—	Amended and Restated Services Agreement, dated October 4, 2005, by and among Global Petroleum Corp., Global Companies LLC, Global Montello Group LLC, and Chelsea Sandwich LLC (incorporated herein by reference to Exhibit 10.3 to the Current Report on Form 8-K filed on October 11, 2005).
10.3		—	Second Amended and Restated Terminal Storage and Throughput Agreement, dated October 4, 2005 by and among Global Petroleum Corp., Global Companies LLC and Global Montello Group LLC (incorporated herein by reference to Exhibit 10.5 to the Current Report on Form 8-K filed on October 11, 2005).
10.4	^	—	Employment Agreement dated April 19, 2006, by and between Global GP LLC and Thomas J. Hollister (incorporated herein by reference to Exhibit 99.1 to the Current Report on Form 8-K filed on May 11, 2006).
10.5	^	—	Employment Agreement dated February 1, 2007, by and between Global GP LLC and Edward J. Faneuil (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on February 6, 2007).
10.6		—	Terminals Sale and Purchase Agreement, dated March 16, 2007 by and between Global Partners LP and ExxonMobil Oil Corporation (incorporated herein by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q filed on August 9, 2007).
10.7	^	—	Forms of LTIP Grant Agreements dated August 14, 2007 (Named Executive Officers who are party to an employment agreement with Global GP LLC) (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on August 20, 2007).
10.8	^	—	Form of LTIP Grant Agreement (Directors) (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on August 20, 2007).
10.9	^	—	Form of LTIP Grant Agreement (General) (incorporated herein by reference to Exhibit 10.3 to the Current Report on Form 8-K filed on August 20, 2007).
10.10		—	Terminals Sale and Purchase Agreement, dated July 9, 2007 by and between Global Partners LP and ExxonMobil Oil Corporation (incorporated herein by reference to Exhibit 10.21 to the Annual Report on Form 10-K filed on March 14, 2008).
10.11	^	—	Employment Agreement dated December 31, 2008, by and between Global GP LLC and Eric S. Slifka (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on January 7, 2009).
10.12	^	—	Amendment No. 1 to Employment Agreement dated December 31, 2008, by and between Global GP LLC and Thomas Hollister (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on January 7, 2009).

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			Description

10.13	^	—	Amendment No. 1 to Employment Agreement dated December 31, 2008, by and between Global GP LLC and Edward J. Faneuil (incorporated herein by reference to Exhibit 10.3 to the Current Report on Form 8-K filed on January 7, 2009).
10.14	^	—	Amended and Restated Deferred Compensation Agreement dated December 31, 2008, by and between Global GP LLC and Edward J. Faneuil (incorporated herein by reference to Exhibit 10.4 to the Current Report on Form 8-K filed on January 7, 2009).
10.15	^	—	First Amendment to LTIP Grant Agreement dated December 31, 2008 for Eric Slifka (incorporated herein by reference to Exhibit 10.5 to the Current Report on Form 8-K filed on January 7, 2009).
10.16	^	—	First Amendment to LTIP Grant Agreement (Named Executive Officers who are party to an employment agreement with Global GP LLC (except Mr. Slifka)), LTIP Grant Agreement (Directors) and LTIP Grant Agreement (General) dated December 31, 2008 (incorporated herein by reference to Exhibit 10.6 to the Current Report on Form 8-K filed on January 7, 2009).
10.17	^	—	Amendment No. 1 to Employment Agreement dated February 4, 2009, by and between Global GP LLC and Eric S. Slifka (incorporated herein by reference to Exhibit 10.30 to the Annual Report on Form 10-K filed on March 13, 2009).
10.18	^	—	Amendment No. 2 to Employment Agreement dated February 4, 2009, by and between Global GP LLC and Thomas Hollister (incorporated herein by reference to Exhibit 10.31 to the Annual Report on Form 10-K filed on March 13, 2009).
10.19	^	—	Amendment No. 2 to Employment Agreement dated February 4, 2009, by and between Global GP LLC and Edward J. Faneuil (incorporated herein by reference to Exhibit 10.32 to the Annual Report on Form 10-K filed on March 13, 2009).
10.20	^	—	Amendment No. 3 to Employment Agreement dated March 11, 2009, by and between Global GP LLC and Edward J. Faneuil (incorporated herein by reference to Exhibit 10.33 to the Annual Report on Form 10-K filed on March 13, 2009).
10.21	^	—	Supplemental Executive Retirement Plan dated December 31, 2009, between Global GP LLC and Edward J. Faneuil (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on January 7, 2010).
10.22	^	—	Supplemental Executive Retirement Plan dated December 31, 2009, between Global GP LLC and Charles A. Rudinsky (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on January 7, 2010).
10.23		—	First Amendment to Second Amended and Restated Terminal Storage Rental and Throughput Agreement, dated May 12, 2010 among Global Petroleum Corp., Global Companies LLC and Global Montello Group Corp. (incorporated herein by reference to Exhibit 10.3 to the Current Report on Form 8-K filed on May 18, 2010).
10.24		—	Sale and Purchase Agreement, dated May 24, 2010 among ExxonMobil Oil Corporation and Exxon Mobil Corporation, as sellers, and Global Companies LLC (incorporated herein by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q filed on August 6, 2010).
10.25		—	First Amendment to Sale and Purchase Agreement, effective August 12, 2010 among ExxonMobil Oil Corporation and Exxon Mobil Corporation, as sellers, and Global Companies LLC (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on August 31, 2010).

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			Description

10.26		—	Second Amendment to Sale and Purchase Agreement, dated September 7, 2010, among ExxonMobil Oil Corporation and Exxon Mobil Corporation, as sellers, and Global Companies LLC, as buyer (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on September 9, 2010).
10.27	^	—	Amendment No. 4 to Employment Agreement dated November 2, 2010 by and between Global GP LLC and Edward J. Faneuil (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on November 8, 2010).
10.28	††	—	Brand Fee Agreement, dated September 3, 2010, between ExxonMobil Oil Corporation and Global Companies LLC (incorporated herein by reference to Exhibit 10.6 to the Quarterly Report on Form 10-Q/A filed on January 20, 2011).
10.29		—	Assignment of Branded Wholesaler PMPA Franchise Agreements, effective March 1, 2011 between Global Companies LLC, Alliance Energy LLC and ExxonMobil Oil Corporation (incorporated herein by reference to Exhibit 10.49 to the Annual Report on Form 10-K filed on March 11, 2011).
10.30	^	—	Employment Agreement dated as of January 1, 2012, by and between Global GP LLC and Eric S. Slifka (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on January 6, 2012).
10.31	^	—	Amendment No. 5 to Employment Agreement dated December 31, 2011, by and between Global GP LLC and Edward J. Faneuil (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on January 6, 2012).
10.32		—	Business Opportunity Agreement, dated March 1, 2012, by and among Alfred A. Slifka, Richard Slifka and Global Partners LP (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on March 7, 2012).
10.33	^	—	Employment Agreement dated March 1, 2012, by and between Global GP LLC and Andrew P. Slifka (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on March 7, 2012).
10.34	^	—	Deferred Compensation Agreement dated September 23, 2009, by and between Alliance Energy LLC and Edward J. Faneuil (incorporated herein by reference to Exhibit 10.53 to the Annual Report on Form 10-K filed on March 12, 2012).
10.35		—	First Amendment to Amended and Restated Services Agreement, dated as of July 24, 2006, by and among Global Petroleum Corp., Global Companies LLC, Global Montello Group Corp. and Chelsea Sandwich LLC (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on March 15, 2012).
10.36		—	Second Amendment to Amended and Restated Services Agreement, dated March 9, 2012, by and among Global Petroleum Corp., Global Companies LLC, Global Montello Group Corp., Chelsea Sandwich LLC and Alliance Energy LLC (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on March 15, 2012).
10.37		—	Services Agreement, dated March 9, 2012, by and between Global Companies LLC and AE Holdings Corp. (incorporated herein by reference to Exhibit 10.3 to the Current Report on Form 8-K filed on March 15, 2012).
10.38	^	—	General Partners LP Long-Term Incentive Plan (As Amended and Restated Effective June 22, 2012) (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on June 25, 2012).

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			Description

10.39		—	Second Amendment to the Second Amended and Restated Terminal Storage Rental and Throughput Agreement, dated November 14, 2012, among Global Petroleum Corp., Global Companies LLC, Glen Hes and Global Montello Group Corp. (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on November 20, 2012).
10.40		—	Note Purchase Agreement, dated as of February 14, 2013, by and among Global Partners LP and GLP Finance Corp., as Issuers, and FS Energy and Power Fund, as Purchaser (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on February 21, 2013).
10.41	^	—	Retirement, Consulting and Noncompete Agreement, dated April 23, 2013, by and between Global GP LLC and Thomas Hollister (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on April 26, 2013).
10.42	^	—	Form of Phantom Unit Award Agreement for Employees under Global Partners LP Long-Term Incentive Plan (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on July 3, 2013).
10.43	^	—	Form of Phantom Unit Award Agreement for Directors under Global Partners LP Long-Term Incentive Plan (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on July 3, 2013).
10.44	^	—	Executive Change of Control Agreement, effective July 1, 2013, by and between Global GP LLC and Daphne H. Foster (incorporated herein by reference to Exhibit 10.3 to the Current Report on Form 8-K filed on July 3, 2013).
10.45	^	—	Executive Change of Control Agreement, effective July 1, 2013, by and between Global GP LLC and Mark Romaine (incorporated herein by reference to Exhibit 10.4 to the Current Report on Form 8-K filed on July 3, 2013).
10.46	^	—	Executive Change of Control Agreement, effective July 1, 2013, by and between Global GP LLC and Charles A. Rudinsky (incorporated herein by reference to Exhibit 10.5 to the Current Report on Form 8-K filed on July 3, 2013).
10.47	^	—	Form of Confidentiality, Non-Solicitation, and Non-Competition Agreement for Phantom Unit Award Recipients (incorporated herein by reference to Exhibit 10.6 to the Current Report on Form 8-K filed on July 3, 2013).
10.48	^	—	Confidentiality, Non-Solicitation, and Non-Competition Agreement, effective July 1, 2013, by and between Global GP LLC and Daphne H. Foster (incorporated herein by reference to Exhibit 10.7 to the Current Report on Form 8-K filed on July 3, 2013).
10.49	^	—	Confidentiality, Non-Solicitation, and Non-Competition Agreement, effective July 1, 2013, by and between Global GP LLC and Mark Romaine (incorporated herein by reference to Exhibit 10.8 to the Current Report on Form 8-K filed on July 3, 2013).
10.50	^	—	Memorandum to Thomas J. Hollister, Follow-up Understandings, dated July 9, 2013 (incorporated herein by reference to Exhibit 10.9 to the Quarterly Report on Form 10-Q filed on November 7, 2013).
10.51		—	Note Purchase Agreement, dated as of December 23, 2013, by and among Global Partners LP and GLP Finance Corp., as Issuers, and 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 (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on December 26, 2013).

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			Description

10.52	*††		Second Amended and Restated Credit Agreement, dated as of December 16, 2013, among Global Operating LLC, Global Companies LLC, Global Montello Group Corp., Glen Hes Corp., Chelsea Sandwich LLC, GLP Finance Corp., Global Energy Marketing LLC, Global Energy Marketing II LLC, Global CNG LLC, Alliance Energy LLC and Cascade Kelly Holdings LLC as borrowers, Bank of America, N.A., as Administrative Agent, Swing Line Lender, Alternative Currency Fronting Lender and L/C Issuer, JPMorgan Chase Bank, N.A. and Wells Fargo Bank, N.A. as Co-Syndication Agents, RBS Citizens NA, Societe Generale and Standard Chartered Bank as Co-Documentation Agents, and Banc of America Merrill Lynch, JP Morgan Securities Inc. and Wells Fargo Securities, LLC as Joint Lead Arrangers and Joint Book Managers.
21.1	*	—	List of Subsidiaries of Global Partners LP.
23.1	*	—	Consent of Ernst & Young LLP.
31.1	*	—	Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of Global GP LLC, general partner of Global Partners LP.
31.2	*	—	Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of Global GP LLC, general partner of Global Partners LP.
32.1	†	—	Section 1350 Certification of Chief Executive Officer of Global GP LLC, general partner of Global Partners LP.
32.2	†	—	Section 1350 Certification of Chief Financial Officer of Global GP LLC, general partner of Global Partners LP.
101.INS	*	—	XBRL Instance Document.
101.SCH	*	—	XBRL Taxonomy Extension Schema Document.
101.CAL	*	—	XBRL Taxonomy Extension Calculation Linkbase Document.
101.LAB	*	—	XBRL Taxonomy Extension Labels Linkbase Document.
101.PRE	*	—	XBRL Taxonomy Extension Presentation Linkbase Document.
101.DEF	*	—	XBRL Taxonomy Extension Definition Linkbase Document.

^: Management contract or compensatory plan or arrangement.
*: Filed herewith.
†: Not deemed "filed" for purposes of Section 18 of the Securities Exchange Act of 1934 or otherwise subject to the liability of that section.
**: Schedules and similar attachments have been omitted pursuant to Item 601(b)(2) of Regulation S-K. The Partnership undertakes to furnish supplementally copies of any of the omitted schedules and exhibits upon request by the U.S. Securities and Exchange Commission.
††: Portions of this exhibit have been omitted pursuant to a request for confidential treatment. The omitted information has been filed separately with the Securities and Exchange Commission.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on March 31, 2014.

Signature		Title


/s/ ERIC SLIFKA Eric Slifka		President, Chief Executive Officer and Director (Principal Executive Officer)
/s/ DAPHNE H. FOSTER Daphne H. Foster		Chief Financial Officer (Principal Financial Officer)
/s/ CHARLES A. RUDINSKY Charles A. Rudinsky		Executive Vice President, Chief Accounting Officer and Co-Director of Mergers and Acquisitions (Principal Accounting Officer)
/s/ ANDREW SLIFKA Andrew Slifka		Executive Vice President, President, Alliance Gasoline Division and Director
/s/ RICHARD SLIFKA Richard Slifka		Chairman
/s/ DAVID K. MCKOWN David K. McKown		Director
/s/ ROBERT J. MCCOOL Robert J. McCool		Director
/s/ KENNETH I. WATCHMAKER Kenneth I. Watchmaker		Director

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INDEX TO FINANCIAL STATEMENTS


GLOBAL PARTNERS LP FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting Firm		F-2
Consolidated Balance Sheets as of December 31, 2013 and 2012		F-3
Consolidated Statements of Income for the years ended December 31, 2013, 2012 and 2011		F-4
Consolidated Statements of Comprehensive Income for the years ended December 31, 2013, 2012 and 2011		F-5
Consolidated Statements of Cash Flows for the years ended December 31, 2013, 2012 and 2011		F-6
Consolidated Statements of Partners' Equity for the years ended December 31, 2013, 2012 and 2011		F-7
Notes to Consolidated Financial Statements		F-8

F-1

Table of Contents

Report of Independent Registered Public Accounting Firm

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

We have audited the accompanying consolidated balance sheets of Global Partners LP ("the Partnership") 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. Our audits also included the financial statement schedule listed in the Index at Item 15(a). These financial statements and schedule are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Global Partners LP at December 31, 2013 and 2012, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2013, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), 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) and our report dated March 31, 2014 expressed an adverse opinion thereon.

/s/ERNST &YOUNG LLP

Boston, Massachusetts
March 31, 2014

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GLOBAL PARTNERS LP

CONSOLIDATED BALANCE SHEETS

(In thousands, except unit data)

	December 31,

	2013			2012
Assets
Current assets:
Cash and cash equivalents	$	9,217		$	5,977
Accounts receivable (less allowance of $7,114 and $4,732 as of December 31, 2013 and 2012, respectively)		686,392			696,762
Accounts receivable—affiliates		1,404			1,307
Inventories		572,806			634,667
Brokerage margin deposits		21,792			54,726
Fair value of forward fixed price contracts		46,007			48,062
Prepaid expenses and other current assets		36,693			65,432


Total current assets		1,374,311			1,506,933
Property and equipment, net		803,636			712,322
Intangible assets, net		67,769			60,822
Goodwill		154,078			32,326
Other assets		28,128			17,349


Total assets	$	2,427,922		$	2,329,752




Liabilities and partners' equity
Current liabilities:
Accounts payable	$	781,119		$	759,698
Working capital revolving credit facility—current portion		—			83,746
Line of credit		3,700			—
Environmental liabilities—current portion		3,377			4,341
Trustee taxes payable		80,216			91,494
Accrued expenses and other current liabilities		65,963			71,442
Obligations on forward fixed price contracts		38,197			34,474


Total current liabilities		972,572			1,045,195
Working capital revolving credit facility—less current portion		327,000			340,754
Revolving credit facility		434,700			422,000
Senior notes		148,268			—
Environmental liabilities—less current portion		37,762			39,831
Other long-term liabilities		44,440			45,511


Total liabilities		1,964,742			1,893,291
Commitments and contingencies (see Note 13)		—			—
Partners' equity
Global Partners LP equity:
Common unitholders (27,430,563 units issued and 27,260,747 outstanding at December 31, 2013 and 27,430,563 units issued and 27,310,648 outstanding at December 31, 2012)		426,785			456,538
General partner interest (0.83% interest with 230,303 equivalent units outstanding at December 31, 2013 and December 31, 2012)		(238	)		(407	)
Accumulated other comprehensive loss		(11,310	)		(19,670	)


Total Global Partners LP equity		415,237			436,461
Noncontrolling interest		47,943			—


Total partners' equity		463,180			436,461


Total liabilities and partners' equity	$	2,427,922		$	2,329,752

The accompanying notes are an integral part of these consolidated financial statements.

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GLOBAL PARTNERS LP

CONSOLIDATED STATEMENTS OF INCOME

(In thousands, except per unit data)

	Year Ended December 31,

	2013			2012			2011
Sales	$	19,589,608		$	17,625,997		$	14,835,729
Cost of sales		19,183,779			17,292,509			14,626,131


Gross profit		405,829			333,488			209,598
Costs and operating expenses:
Selling, general and administrative expenses		115,491			95,710			73,882
Operating expenses		185,713			140,413			73,534
Restructuring charges		—			—			2,030
Amortization expense		19,216			7,024			4,800


Total costs and operating expenses		320,420			243,147			154,246


Operating income		85,409			90,341			55,352
Interest expense		(43,537	)		(42,021	)		(35,932	)


Income before income tax expense		41,872			48,320			19,420
Income tax expense		(819	)		(1,577	)		(68	)


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
Less: General partner's interest in net income, including incentive distribution rights		(3,521	)		(1,212	)		(684	)


Limited partners' interest in net income	$	39,094		$	45,531		$	18,668




Basic net income per limited partner unit	$	1.43		$	1.73		$	0.88




Diluted net income per limited partner unit	$	1.42		$	1.71		$	0.87




Basic weighted average limited partner units outstanding		27,329			26,393			21,280




Diluted weighted average limited partner units outstanding		27,560			26,567			21,474




Distributions per limited partner unit	$	2.34		$	2.06		$	2.00

The accompanying notes are an integral part of these consolidated financial statements.

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GLOBAL PARTNERS LP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In thousands)

(Unaudited)

	Year Ended December 31,

	2013		2012			2011
Net income	$	41,053	$	46,743		$	19,352
Other comprehensive income:
Change in fair value of cash flow hedges		3,930		2,591			(4,039	)
Change in pension liability		4,430		(1,766	)		(2,694	)


Total other comprehensive income (loss)		8,360		825			(6,733	)


Comprehensive income		49,413		47,568			12,619
Comprehensive loss attributable to noncontrolling interest		1,562		—			—


Comprehensive income attributable to Global Partners LP	$	50,975	$	47,568		$	12,619

The accompanying notes are an integral part of these consolidated financial statements.

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GLOBAL PARTNERS LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

	Year Ended December 31,

	2013			2012			2011
Cash flows from operating activities
Net income	$	41,053		$	46,743		$	19,352
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation and amortization		77,134			45,458			30,359
Amortization of deferred financing fees		6,897			5,753			4,723
Amortization of senior notes discount		368			—			—
Bad debt expense		4,145			869			1,860
Stock-based compensation expense		1,806			6			361
Gain on disposition of property and equipment		(1,273	)		627			222
Deferred income taxes		336			1,217			—
Curtailment gain		—			(469	)		—
Changes in operating assets and liabilities, exclusive of business combinations:
Accounts receivable		8,524			(57,160	)		(70,464	)
Accounts receivable—affiliate		(97	)		469			(546	)
Inventories		61,992			40,898			(77,313	)
Broker margin deposits		32,934			(10,791	)		(28,434	)
Prepaid expenses, all other current assets and other assets		11,226			(8,449	)		(29,520	)
Accounts payable		18,667			146,947			132,307
Trustee taxes payable		(11,278	)		5,002			6,695
Change in fair value of forward fixed price contracts		5,778			(9,845	)		(10,958	)
Accrued expenses, all other current liabilities and other long-term liabilities		(3,065	)		25,177			3,999


Net cash provided by (used in) operating activities		255,147			232,452			(17,357	)
Cash flows from investing activities
Acquisitions		(185,262	)		(188,748	)		—
Capital expenditures		(67,132	)		(44,872	)		(15,957	)
Proceeds from sale of property and equipment		9,187			7,132			2,588


Net cash used in investing activities		(243,207	)		(226,488	)		(13,369	)
Cash flows from financing activities
Proceeds from public offerings, net		—			—			69,626
(Payments on) borrowings from working capital revolving credit facility		(97,500	)		(164,400	)		102,200
Borrowings from (payments on) revolving credit facility		12,700			217,000			(95,000	)
Proceeds from issuance of term loan		115,000			—			—
Repayment of term loan		(115,000	)		—			—
Borrowing from line of credit		3,700			—			—
Proceeds from senior notes, net of discount		147,900			—			—
Repurchase of common units		(4,590	)		(2,152	)		(658	)
Repurchased units withheld for tax obligations		(2,086	)		(96	)		(675	)
Noncontrolling interest capital contribution		1,425			—			—
Distribution to noncontrolling interest		(2,920	)
Distributions to partners		(67,329	)		(54,667	)		(42,800	)


Net cash (used in) provided by financing activities		(8,700	)		(4,315	)		32,693
Cash and cash equivalents
Increase in cash and cash equivalents		3,240			1,649			1,967
Cash and cash equivalents at beginning of year		5,977			4,328			2,361


Cash and cash equivalents at end of year	$	9,217		$	5,977		$	4,328




Supplemental information (see Note 21)
Non-cash investing activities (see Note 21)

The accompanying notes are an integral part of these consolidated financial statements.

F-6

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GLOBAL PARTNERS LP

CONSOLIDATED STATEMENTS OF PARTNERS' EQUITY

(In thousands)

	Common Unitholders			Subordinated Unitholders			General Partner Interest			Other Comprehensive Income			Noncontrolling Interest			Total Partners' Equity

Balance December 31, 2010	$	292,267		$	(1,623	)	$	(66	)	$	(13,762	)	$	—		$	276,816
Conversion of subordinated units to common units		(1,623	)		1,623			—			—			—			—
Proceeds from public offering, net		69,626			—			—			—			—			69,626
Net income		18,668			—			684			—			—			19,352
Other comprehensive income		—			—			—			(6,733	)		—			(6,733	)
Stock-based compensation		361			—			—			—			—			361
Distributions to partners		(41,863	)		—			(937	)		—			—			(42,800	)
Repurchase of common units		(658	)		—			—			—			—			(658	)
Repurchased units withheld for tax obligations		(675	)		—			—			—			—			(675	)


Balance December 31, 2011		336,103			—			(319	)		(20,495	)		—			315,289
Issuance of common units in connection with the acquisition of Alliance		130,513			—			—			—			—			130,513
Net income		45,531			—			1,212			—			—			46,743
Other comprehensive income		—			—			—			825			—			825
Stock-based compensation		6			—			—			—			—			6
Distributions to partners		(53,514	)		—			(1,300	)		—			—			(54,814	)
Repurchase of common units		(2,152	)		—			—			—			—			(2,152	)
Repurchased units withheld for tax obligations		(96	)		—			—			—			—			(96	)
Phantom unit dividends		147			—			—			—			—			147


Balance at December 31, 2012		456,538			—			(407	)		(19,670	)		—			436,461
Net income (loss)		39,094			—			3,521			—			(1,562	)		41,053
Acquisition of noncontrolling interest, at fair value					—			—			—			51,000			51,000
Noncontrolling interest capital contribution		—			—			—			—			1,425			1,425
Distribution to noncontrolling interest		—			—			—			—			(2,920	)		(2,920	)
Other comprehensive income		—			—			—			8,360			—			8,360
Stock-based compensation		1,806			—			—			—			—			1,806
Distributions to partners		(64,190	)		—			(3,352	)		—			—			(67,542	)
Repurchase of common units		(4,590	)		—			—			—			—			(4,590	)
Repurchased units withheld for tax obligation		(2,086	)		—			—			—			—			(2,086	)
Phantom unit dividends		213			—			—			—			—			213


Balance at December 31, 2013	$	426,785		$	—		$	(238	)	$	(11,310	)	$	47,943		$	463,180

The accompanying notes are an integral part of these consolidated financial statements.

F-7

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1. Organization and Basis of Presentation

Organization

Global Partners LP (the "Partnership") is a publicly traded Delaware master limited partnership formed in March 2005. As of December 31, 2013, the Partnership 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. Global GP LLC, the Partnership's general partner (the "General Partner") manages the Partnership's operations and activities and employs its officers and substantially all of its personnel, except for its gasoline station and convenience store employees and certain union personnel who are employed by GMG.

The Partnership is a midstream logistics and marketing company. The Partnership is 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. The Partnership also engages 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. The Partnership owns, controls or has 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"). The Partnership also owns and controls terminals in North Dakota and Oregon that extend its origin-to-destination capabilities. The Partnership is 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. The Partnership receives revenue from retail sales of gasoline, convenience store sales and gasoline station rental income. The Partnership is also a distributor of natural gas and propane.

On March 1, 2012, the Partnership acquired from AE Holdings Corp. ("AE Holdings") 100% of the outstanding membership interests in Alliance Energy LLC ("Alliance") (see Note 3). 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. No member of the Slifka family owned a controlling interest in AE Holdings, nor currently owns a controlling interest in the General Partner. Three independent directors of the General Partner's board of directors serve on a conflicts committee. The conflicts committee unanimously approved the Alliance acquisition and received advice from its independent counsel and independent financial adviser.

On February 1, 2013, the Partnership acquired a 60% membership interest in Basin Transload LLC ("Basin Transload"), and on February 15, 2013, the Partnership acquired 100% of the membership interests in Cascade Kelly Holdings LLC ("Cascade Kelly"). See Note 3.

The General Partner, which holds a 0.83% general partner interest in the Partnership, is owned by affiliates of the Slifka family. As of December 31, 2013, affiliates of the General Partner, including its directors and executive officers and their affiliates, owned 11,599,336 common units, representing a 42.3% limited partner interest.

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Table of Contents

GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 2. Summary of Significant Accounting Policies

Basis of Consolidation and Presentation

The financial results of Alliance for the ten months ended December 31, 2012 are included in the accompanying statement of income for the year ended December 31, 2012. The financial results of Basin Transload for the eleven months ended December 31, 2013 and of Cascade Kelly for the ten and one-half months ended December 31, 2013 are included in the accompanying statement of income for the year ended December 31, 2013. The Partnership consolidates the balance sheet and results of operations of Basin Transload because the Partnership controls the entity. The accompanying consolidated financial statements as of December 31, 2013 and 2012 and for the years ended December 31, 2013, 2012 and 2011 reflect the accounts of the Partnership. Upon consolidation, all intercompany balances and transactions have been eliminated.

Noncontrolling Interest

These financial statements reflect the application of ASC 810, "Consolidations" ("ASC 810") which establishes accounting and reporting standards that require: (i) the ownership interest in subsidiaries held by parties other than the parent to be clearly identified and presented in the consolidated balance sheet within shareholder's equity, but separate from the parent's equity; (ii) the amount of consolidated net income attributable to the parent and the noncontrolling interest to be clearly identified and presented on the face of the consolidated statement of operations and (iii) changes in a parent's ownership interest while the parent retains its controlling financial interest in its subsidiary to be accounted for consistently.

The Partnership acquired a 60% interest in Basin Transload on February 1, 2013. After evaluating ASC 810, the Partnership concluded it is appropriate to consolidate the balance sheet and statement of operations of Basin Transload based on an evaluation of the outstanding voting interests. Amounts pertaining to the noncontrolling ownership interest held by third parties in the financial position and operating results of the Partnership are reported as a noncontrolling interest in the accompanying consolidated balance sheet and statement of income.

Reclassification

Prior year amounts for amortization of deferred financing fees have been reclassified from selling, general and administrative expenses to interest expense to conform to the current year presentation.

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results may differ from those estimates under different assumptions or conditions. Among the estimates made by management are (i) estimated fair value of assets and liabilities acquired in a business combination and identification of associated goodwill and intangible assets, (ii) mark-to-market gains and losses on derivative instruments, (iii) accruals and contingent liabilities, (iv) allowance for doubtful accounts, (v) Level 3 valuation for crude oil forward purchase and sales contracts, and (vi) assumptions used to evaluate goodwill impairment. Although the Partnership believes these estimates are reasonable, actual results could differ from these estimates.

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 2. Summary of Significant Accounting Policies (continued)

Cash and Cash Equivalents

The Partnership considers highly liquid investments with original maturities of three months or less at the time of purchase to be cash equivalents. The carrying value of cash and cash equivalents, including broker margin accounts, approximates fair value.

Accounts Receivable

The Partnership's accounts receivable primarily result from sales of refined petroleum products, renewable fuels, crude oil, natural gas and propane to its customers. The majority of the Partnership's accounts receivable relates to its petroleum marketing and crude oil activities that can generally be described as high volume and low margin activities. The Partnership makes a determination of the amount, if any, of a line of credit it may extend to a customer based on the form and amount of financial performance assurances the Partnership requires. Such financial assurances are commonly provided to the Partnership in the form of standby letters of credit, personal guarantees or corporate guarantees.

The Partnership reviews all accounts receivable balances on a monthly basis and records a reserve for estimated amounts it expects will not be fully recovered. At December 31, 2013 and 2012, substantially all of the Partnership's accounts receivable classified as current assets were within payment terms.

Inventories

Except for its convenience store inventory and its Renewable Identification Numbers ("RINs") inventory, the Partnership hedges substantially all of its 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, the Partnership has convenience store inventory and RIN inventory which are carried at the lower of historical cost or market. Inventory held at locations in Oregon and North Dakota was nominal at December 31, 2013 and is carried at the lower of cost or market.

Inventories consisted of the following at December 31 (in thousands):

	2013		2012

Distillates: home heating oil, diesel and kerosene	$	272,760	$	235,029
Gasoline		96,539		144,269
Gasoline blendstocks		54,076		119,932
Renewable identification numbers (RINs)		3,186		19,384
Crude oil		87,022		80,273
Residual oil		48,793		29,150
Propane and other		3,443		—
Convenience store inventory		6,987		6,630


Total	$	572,806	$	634,667

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 2. Summary of Significant Accounting Policies (continued)

In addition to its own inventory, the Partnership has exchange agreements for petroleum products with unrelated third-party suppliers, whereby it may draw inventory from these other suppliers (seeRevenue Recognition) and suppliers may draw inventory from the Partnership. Positive exchange balances are accounted for as accounts receivable and amounted to $48.2 million and $120.9 million at December 31, 2013 and December 31, 2012, respectively. Negative exchange balances are accounted for as accounts payable and amounted to $46.7 million and $139.5 million at December 31, 2013 and December 31, 2012, respectively. Exchange transactions are valued using current carrying costs.

Property and Equipment

Property and equipment are stated at cost less accumulated depreciation. Expenditures for routine maintenance, repairs and renewals are charged to expense as incurred, and major improvements are capitalized. Depreciation is charged to cost of sales and selling, general and administrative expenses over the estimated useful lives of the applicable assets, using straight-line methods, and accelerated methods are used for income tax purposes. When applicable, the Partnership capitalizes interest on qualified long-term projects and depreciates it over the life of the related asset. The estimated useful lives are as follows:


Buildings, docks, terminal facilities and improvements		5-25 years
Gasoline stations		25 years
Gasoline station equipment		7 years
Fixtures, equipment and capitalized internal use software		3-7 years

The Partnership capitalizes certain costs, including internal payroll and external direct project costs incurred in connection with developing or obtaining software designated for internal use. These costs are included in property and equipment and are amortized over the estimated useful lives of the related software.

Intangibles

Intangibles are carried at cost less accumulated amortization. For assets with determinable useful lives, amortization is computed over the estimated economic useful lives of the respective intangible assets, ranging from 2 to 20 years.

Impairment Long-Lived Assets

The Partnership's long-lived assets include property and equipment and intangible assets. Accounting and reporting guidance for long-lived assets requires that a long-lived asset (group) be reviewed for impairment only when events or changes in circumstances indicate that the carrying amount might not be recoverable. Accordingly, the Partnership evaluates for impairment whenever indicators of impairment are identified. If indicators of impairment are present, the Partnership assesses 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. There were no impairment charges required in 2013, 2012 and 2011.

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Note 2. Summary of Significant Accounting Policies (continued)

Goodwill

Goodwill represents the future economic benefits arising from assets acquired in a business combination that are not individually identified and separately recognized. The Partnership has concluded that its operating segments are also its reporting units. A portion of the Partnership's goodwill is allocated to the Wholesale reporting unit, and a portion of the goodwill is allocated to the Gasoline Distribution and Station Operations ("GDSO") 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. Factors considered in the qualitative analysis include changes in the business and industry, as well as macro-economic conditions, that would influence the fair value of the reporting unit as well as changes in the carrying values of the reporting unit. If necessary, the Partnership will 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 a discounted cash flow approach and a market comparables approach. In the quantitative assessment, the Partnership compares 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 the Partnership would record an impairment loss equal to the difference. During 2013, the Partnership completed a qualitative assessment for the GDSO reporting unit and no impairment was required. A quantitative assessment was most recently completed in 2012 for this reporting unit. The goodwill allocated to the Wholesale reporting unit was acquired in 2013. Thus, the Partnership elected to complete a step one quantitative assessment for this reporting unit and no such impairment was identified.

Environmental and Other Liabilities

The Partnership accrues 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.

Recoveries of environmental remediation costs from other parties are recognized as assets when all related contingencies are resolved, generally upon cash receipt.

The Partnership is subject to other contingencies, including legal proceedings and claims arising out of its 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 previously owned. Further, due to the lack of adequate information and the potential impact of present regulations and any future regulations, there are

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Note 2. Summary of Significant Accounting Policies (continued)

certain circumstances in which no range of potential exposure may be reasonably estimated. See Notes 9 and 20.

Asset Retirement Obligations

The Partnership is required to account for the legal obligations associated with the long-lived assets that result from the acquisition, construction, development or operation of long-lived assets. Such asset retirement obligations specifically pertain to the treatment of underground gasoline storage tanks ("USTs") that exist in those U.S. states which statutorily require removal of the USTs at a certain point in time. Specifically, the Partnership's retirement obligations consist of the estimated costs of removal and disposals of USTs in specific states. The fair value of a liability for an asset retirement obligation is recognized in the year in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying cost of the asset. In certain states, the Partnership has the ability to request reimbursement for UST removal costs from state tank funds. Recoveries for UST costs from these state tank funds are recorded as income in the period received. The Partnership recorded approximately $2.1 million and $1.7 million in total asset retirement obligations which are included in other long-term liabilities in the accompanying balance sheets at December 31, 2013 and 2012, respectively.

Leases

The Partnership leases office space, computer and other equipment and railcars through various lease arrangements with various expiration dates. The Partnership is a party to terminal and throughput lease arrangements with certain counterparties at various unrelated terminals. The Partnership is also a party to lease agreements with the Port of St. Helens for land and for access rights to a rail spur located at the Partnership's Oregon facility. The leases assumed in the acquisition were determined to be at market value and, therefore, did not result in an asset or liability recorded in purchase accounting. In addition, the Partnership leases gasoline stations, primarily land and buildings, under operating leases with various expiration dates.

The Partnership also leases gasoline stations and certain equipment to gasoline station operators under operating leases with various expiration dates.

Accounting and reporting guidance for leases requires that leases be evaluated and classified as operating or capital leases for financial reporting purposes. The lease term used for lease evaluation includes option periods only in instances in which the exercise of the option period can be reasonably assured and failure to exercise such options would result in an economic penalty. Lease rental expense is recognized on a straight-line basis over the term of the lease.

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. The Partnership may also provide for shipping costs at the time of sale, which are included in cost of sales. In addition, the Partnership generates revenue from its logistics activities when it engages in the storage, transloading and shipment of products owned by others. Revenue for logistics services is recognized as services are provided. 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. The Partnership also recognizes 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.

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Note 2. Summary of Significant Accounting Policies (continued)

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 the Partnership's end markets. Any net differential for exchange agreements is to be recorded as a nonmonetary adjustment of inventory costs.

The Partnership collects 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 the Partnership's policy to exclude trustee taxes from revenues and cost of sales and account for them as current liabilities.

Income Taxes

Section 7704 of the Internal Revenue Code provides that publicly-traded partnerships are, as a general rule, taxed as corporations. However, an exception, referred to as the "Qualifying Income Exception," exists under Section 7704(c) with respect to publicly-traded partnerships of which 90% or more of the gross income for every taxable year consists of "qualifying income." Qualifying income includes income and gains derived from the transportation, storage and marketing of refined petroleum products and crude oil to resellers and refiners. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income.

Substantially all of the Partnership's income is "qualifying income" for federal income tax purposes and, therefore, is not subject to federal income taxes at the partnership level. Accordingly, no provision has been made for income taxes on the qualifying income in the Partnership's financial statements. Net income for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities and the taxable income allocation requirements under the Partnership's agreement of limited partnership. Individual unitholders have different investment basis depending upon the timing and price at which they acquired their common units. Further, each unitholder's tax accounting, which is partially dependent upon the unitholder's tax position, differs from the accounting followed in the Partnership's consolidated financial statements. Accordingly, the aggregate difference in the basis of the Partnership's net assets for financial and tax reporting purposes cannot be readily determined because information regarding each unitholder's tax attributes in the Partnership is not available to the Partnership.

One of the Partnership's wholly owned subsidiaries, GMG, is a taxable entity for federal and state income tax purposes. Current and deferred income taxes are recognized on the separate earnings of GMG for the years ended December 31, 2013, 2012 and 2011. The after-tax earnings of GMG are included in the earnings of the Partnership. Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes for GMG. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. The Partnership calculates its current and deferred tax provision based on

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 2. Summary of Significant Accounting Policies (continued)

estimates and assumptions that could differ from actual results reflected in income tax returns filed in subsequent years. Adjustments based on filed returns are recorded when identified. See Note 5.

The Partnership recognizes deferred tax assets to the extent that the recoverability of these assets satisfies the "more likely than not" recognition criteria in accordance with accounting guidance regarding income taxes. Based upon projections of future taxable income, the Partnership believes that the recorded deferred tax assets will be realized.

Foreign Currency Transactions

Gains/(losses) realized from transactions denominated in foreign currencies are included in cost of sales in the consolidated statement of income and totaled $(162,000) and $145,000 for the years ended December 31, 2013 and 2012, respectively. No gains or losses were recognized for the year ended December 31, 2011.

Concentration of Risk

Financial instruments that potentially subject the Partnership to concentration of credit risk consist primarily of cash, cash equivalents, accounts receivable, firm commitments and, under certain circumstances, futures contracts, forward fixed price contracts, options and swap agreements, all of which may be used to hedge commodity and interest rate risks. The Partnership invests excess cash primarily in investment-grade securities and, by policy, limits the amount of credit exposure to any one financial institution. The Partnership provides credit in the normal course of its business. The Partnership performs ongoing credit evaluations of its customers and provides for credit losses based on specific information and historical trends. Credit risk on trade receivables is minimized as a result of the Partnership's large customer base. Losses have historically been within management's expectations. See Note 4 for a discussion regarding risk of credit loss related to futures contracts, forward fixed price contracts, options and swap agreements. The Partnership's wholesale and commercial customers of refined petroleum products, renewable fuels, crude oil, natural gas and propane are primarily located in the Northeast. The Partnership's retail gasoline stations are located in Massachusetts, Connecticut, New Hampshire, Rhode Island, New Jersey, New York, Pennsylvania, Maine and Vermont.

Due to the nature of the Partnership's business and its reliance, in part, on consumer travel and spending patterns, the Partnership 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 the Partnership operates, increasing the demand for gasoline and gasoline blendstocks that the Partnership distributes. Therefore, the Partnership's volumes in gasoline and gasoline blendstocks are typically higher in the second and third quarters of the calendar year. As demand for some of the Partnership's 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 the Partnership's quarterly operating results.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 2. Summary of Significant Accounting Policies (continued)

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



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 than¹/2%

The Partnership is dependent on a number of suppliers of fuel-related products, both domestically and internationally. The Partnership is dependent on the suppliers being able to source product on a timely basis and at favorable pricing terms. The loss of certain principal suppliers or a significant reduction in product availability from principal suppliers could have a material adverse effect on the Partnership, at least in the near term. The Partnership believes that its relationships with its suppliers are satisfactory and that the loss of any principal supplier could be replaced by new or existing suppliers.

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. The Partnership principally uses derivative instruments to hedge the commodity risk associated with its inventory and product purchases and sales and to hedge variable interest rates associated with the Partnership's credit facilities.

Fair Value Hedges

The Partnership enters into futures contracts in the normal course of business to reduce the 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 the Partnership's hedge designation on these transactions, the futures contracts are recorded on the Partnership's 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 the Partnership through brokerage margin accounts.

Cash Flow Hedges

The Partnership utilizes various interest rate derivative instruments to hedge variable interest rate on its debt. These derivative instruments are designated as cash flow hedges of the underlying debt. To

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 2. Summary of Significant Accounting Policies (continued)

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, the Partnership 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, the Partnership 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, the Partnership 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, the Partnership 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

The Partnership uses futures contracts, and occasionally swap agreements, to hedge its commodity exposure under forward fixed price purchase and sale commitments on its products. These derivatives are not designated by the Partnership 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 the Partnership's consolidated balance sheet. The related futures contracts (and swaps, if applicable) are also reflected in the Partnership's 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 the Partnership through brokerage margin accounts.

While the Partnership seeks to maintain a position that is substantially balanced within its product purchase activities, it 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 its business, the Partnership engages 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.

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Note 2. Summary of Significant Accounting Policies (continued)

The Partnership also markets and sells natural gas by entering into forward purchase commitments for natural gas when it enters into arrangements for the forward sale commitment of product for physical delivery to third-party users. The Partnership reflects the fair value of forward fixed purchase and sales commitments in its 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, the Partnership 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 sheets. Changes in the fair values of these forward currency contracts are reflected in cost of sales.

Net Income Per Limited Partner Unit

Under the Partnership's partnership agreement, for any quarterly period, the incentive distribution rights ("IDRs") participate in net income only to the extent of the amount of cash distributions actually declared, thereby excluding the IDRs from participating in the Partnership's undistributed net income or losses. Accordingly, the Partnership's undistributed net income is assumed to be allocated to the common and subordinated unitholders, or limited partners' interest, and to the General Partner's general partner interest. On February 16, 2011, all subordinated units converted to common units.

At December 31, 2013 and 2012, common units outstanding as reported in the accompanying consolidated financial statements excluded 169,816 and 119,915 common units, respectively, held on behalf of the Partnership pursuant to its repurchase program (see Note 12). These units are not deemed outstanding for purposes of calculating net income per limited partner unit (basic and diluted).

The following table provides a reconciliation of net income and the assumed allocation of net income to the limited partners' interest for purposes of computing net income per limited partner unit (in thousands, except per unit data):

	Year Ended December 31, 2013

Numerator:	Total			Limited Partner Interest			General Partner Interest			IDRs
Net income attributable to Global Partners LP (1)	$	42,615		$	39,094		$	3,521		$	—




Declared distribution	$	69,070		$	65,356		$	547		$	3,167
Assumed allocation of undistributed net income		(26,455	)		(26,262	)		(193	)		—


Assumed allocation of net income	$	42,615		$	39,094		$	354		$	3,167




Denominator:
Basic weighted average limited partner units outstanding					27,329
Dilutive effect of phantom units					231


Diluted weighted average limited partner units outstanding					27,560
Basic net income per limited partner unit				$	1.43




Diluted net income per limited partner unit				$	1.42

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 2. Summary of Significant Accounting Policies (continued)

	Year Ended December 31, 2012

Numerator:	Total			Limited Partner Interest			General Partner Interest			IDRs
Net income attributable to Global Partners LP (1)	$	46,743		$	45,531		$	1,212		$	—




Declared distribution	$	60,132		$	58,360		$	489		$	1,283
Adjustment to distribution in connection with the Alliance acquisition (2)		(1,929	)		(1,929	)		—			—


Adjusted declared distribution		58,203			56,431			489			1,283
Assumed allocation of undistributed net income		(11,460	)		(10,900	)		(560	)		—


Assumed allocation of net income	$	46,743		$	45,531		$	(71	)	$	1,283




Denominator:
Basic weighted average limited partner units outstanding					26,393
Dilutive effect of phantom units					174						��


Diluted weighted average limited partner units outstanding					26,567
Basic net income per limited partner unit				$	1.73




Diluted net income per limited partner unit				$	1.71

	Year Ended December 31, 2011

Numerator:	Total			Limited Partner Interest			General Partner Interest			IDRs
Net income attributable to Global Partners LP (3)	$	19,352		$	18,668		$	684		$	—




Declared distribution	$	44,112		$	43,160		$	464		$	488
Assumed allocation of undistributed net income		(24,760	)		(24,492	)		(268	)		—


Assumed allocation of net income	$	19,352		$	18,668		$	196		$	488




Denominator:
Basic weighted average limited partner units outstanding					21,280
Dilutive effect of phantom units					194


Diluted weighted average limited partner units outstanding					21,474
Basic net income per limited partner unit				$	0.88




Diluted net income per limited partner unit				$	0.87

(1): Calculation includes the effect of the March 1, 2012 issuance of 5,850,000 common units in connection with the acquisition of Alliance (see Note 3). As a result, the general partner interest was 0.83% and, based on a weighted average, 0.86% for the years ended December 31, 2013 and 2012, respectively.
(2): In connection with the acquisition of Alliance on March 1, 2012 and the issuance of 5,850,000 common units, the Contribution Agreement provided that any declared distribution for the first quarter of 2012 reflect the seller's actual period of ownership during that quarter. The payment by the seller of $1.9 million reflects the timing of the transaction

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Note 2. Summary of Significant Accounting Policies (continued)

(March 1), the seller's 31 days of actual unit ownership in the 91 days of the quarter and the net receipt by seller ($1.0 million) of a pro-rated portion of the quarterly cash distribution of $0.50 per unit paid on the issued 5,850,000 common units.

(3): Calculation includes the effect of the Partnership's November 2010 and February 2011 public offerings. As a result, the general partner interest was, based on a weighted average, 1.09% for year ended December 31, 2011.

On April 24, 2013, the board of directors of the General Partner declared a quarterly cash distribution of $0.5825 per unit for the period from January 1, 2013 through March 31, 2013. On July 23, 2013, the board of directors of the General Partner declared a quarterly cash distribution of $0.5875 per unit for the period from April 1, 2013 through June 30, 2013. On October 23, 2013, the board of directors of the General Partner declared a quarterly cash distribution of $0.60 per unit for the period from July 1, 2013 through September 30, 2013. These declared cash distributions resulted in incentive distributions to the General Partner, as the holder of the IDRs, and enabled the Partnership to exceed its second target level distribution with respect to such IDRs. On January 22, 2014, the board of directors of the General Partner declared a quarterly cash distribution of $0.6125 per unit for the period from October 1, 2013 through December 31, 2013. This declared cash distribution resulted in incentive distributions to the General Partner, as the holder of the IDRs, and enabled the Partnership to exceed its second target level distribution with respect to such IDRs. See Note 14, "Partners' Equity, Allocations and Cash Distributions" for further information.

Accounting Standards or Updates Recently Adopted

In February 2013, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2013-02, "Other Comprehensive Income (Topic 220): Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income." Under this standard, an entity is required to provide information about the amounts reclassified out of Accumulated Other Comprehensive Income ("AOCI") by component. In addition, an entity is required to present, either on the face of the financial statements or in the notes, significant amounts reclassified out of AOCI by the respective line items of net income, but only if the amount reclassified is required to be reclassified in its entirety in the same reporting period. For amounts that are not required to be classified in their entirety to net income, an entity is required to cross-reference to other disclosures that provide additional details about those amounts. This standard does not change the current requirements for reporting net income or other comprehensive income in the financial statements. The Partnership adopted this guidance on January 1, 2013 which did not have a material impact on the Partnership's financial position, results of operations or cash flows.

In January 2013, the FASB issued ASU No. 2013-01, "Balance Sheet (Topic 210): Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities." This standard provides additional guidance on the scope of disclosures about offsetting assets and liabilities. The additional guidance provides that only recognized derivatives, repurchase agreements and reverse repurchase agreements, and securities borrowing and lending transactions would be subject to disclosure requirements. The Partnership adopted this guidance on January 1, 2013 which did not have a material impact on the Partnership's financial position, results of operations or cash flows.

Accounting Standards or Updates Not Yet Effective

In July 2013, the FASB issued ASU No. 2013-11, "Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exist." ASU 2013-11 amends the presentation requirements of ASC 740, "Income Taxes," and requires an

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Note 2. Summary of Significant Accounting Policies (continued)

unrecognized tax benefit to be presented in the financial statements as a reduction to a deferred tax asset for a net operating loss carryforward, similar tax loss, or a tax credit carryforward. To the extent the tax benefit is not available at the reporting date under the governing tax law or if the entity does not intend to use the deferred tax asset for such purpose, the unrecognized tax benefit should be presented as a liability and not combined with deferred tax assets. The ASU is effective for annual periods, and interim periods within those years, beginning after December 15, 2013, which is the Partnership's fiscal 2014. The amendments are to be applied to all unrecognized tax benefits that exist as of the effective date and may be applied retrospectively to each prior reporting period presented. The Partnership is currently evaluating the impact of the adoption of ASU 2013-11 on its consolidated financial statements. The Partnership does not expect the adoption of this standard to have any impact on its consolidated financial statements, as the Partnership's current practice is consistent with this standard.

The Partnership has evaluated the accounting guidance recently issued and has determined that there are no other standards or updates will not have a material impact on its financial position, results of operations or cash flows.

Note 3. Business Combinations

2013 Acquisitions

Basin Transload LLC—On February 1, 2013, the Partnership 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 combined rail loading capacity of 160,000 barrels per day. The purchase price, including expenditures related to certain capital expansion projects, was approximately $91.1 million which the Partnership financed with borrowings under its credit facility.

The acquisition was accounted for using the purchase method of accounting in accordance with the FASB's guidance regarding business combinations. The Partnership's financial statements include the results of operations of its membership interest in Basin Transload subsequent to the acquisition date.

The following table presents the allocation of the purchase price to the estimated fair value of the assets acquired and liabilities assumed at the date of acquisition (in thousands):


Assets purchased:
Accounts receivable	$	2,003
Prepaid expenses		68
Property and equipment		29,112
Intangibles		26,162


Total identifiable assets purchased		57,345
Liabilities assumed:
Accounts payable		(1,326	)


Total liabilities assumed		(1,326	)


Net identifiable assets acquired		56,019
Noncontrolling interest		(51,000	)
Goodwill		86,064


Net assets acquired	$	91,083

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 3. Business Combinations (continued)

The Partnership engaged a third-party valuation firm to assist in the valuation of the Partnership's interest in Basin Transload's property and equipment, intangible assets and noncontrolling interest. The Partnership's third-party valuation firm primarily used the replacement cost methodology to value property and equipment, adjusted for depreciation associated with the age and estimated condition of the assets. The income approach was used to value the intangible assets, which consist principally of customer relationships.

The fair value of the noncontrolling interest was developed by a third-party valuation firm based on the fair value of the acquired business as a whole, reduced by the consideration paid to obtain control. This fair value of the business was estimated based on the fair value of Basin Transload's net assets and applying a reasonable control premium. The fair values of the remaining Basin Transload assets and liabilities noted above approximate their carrying values at February 1, 2013.

The purchase price for the acquisition was allocated to assets acquired and liabilities assumed based on their estimated fair values. The Partnership then allocated the purchase price in excess of net tangible assets acquired to identifiable intangible assets, based upon a valuation from the Partnership's third-party valuation firm. Any excess purchase price over the fair value of the net tangible and intangible assets acquired was allocated to goodwill and assigned to the Wholesale reporting unit. The goodwill recognized is attributed to the unique origin of the acquired locations through which the Partnership's customers can efficiently supply cost-competitive crude oil to destinations on the East and West Coasts. The goodwill also reflects synergies expected to be realized from Basin Transload's logistics services, and those services can benefit the Partnership's existing customers. The goodwill is deductible for income tax purposes.

As part of the purchase price allocation, identifiable intangible assets include customer relationships that are being amortized over two years which is consistent with the contractual period of the existing customers. Amortization expense amounted to $12.0 million for the year ended December 31, 2013. The following table presents the estimated remaining amortization expense for intangible assets acquired in connection with the acquisition (in thousands):


2014	$	11,200
2015		2,690


Total	$	13,890

Cascade Kelly Holdings LLC—On February 15, 2013, the Partnership acquired 100% of the membership interests in Cascade Kelly, which owns a West Coast crude oil and ethanol facility near Portland, Oregon. The total cash purchase price was approximately $94.2 million which the Partnership funded with borrowings under its credit facility and with proceeds from the issuance of the Partnership's unsecured 8.00% senior notes due 2018 (see Note 8). Cascade Kelly's assets include a rail transloading facility serviced by the Burlington Northern Santa Fe Railway, 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. Situated along the Columbia River in Clatskanie, Oregon, the site is located on land leased under a long-term agreement from the Port of St. Helens.

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 3. Business Combinations (continued)

The following table presents the allocation of the purchase price to the estimated fair value of the assets acquired and liabilities assumed at the date of acquisition (in thousands):


Assets purchased:
Accounts receivable	$	296
Inventory		131
Prepaid expenses		96
Property and equipment		60,903


Total identifiable assets purchased		61,426
Liabilities assumed:
Accounts payable		(1,428	)
Other current liabilities		(1,507	)


Total liabilities assumed		(2,935	)


Net identifiable assets acquired		58,491
Goodwill		35,688


Net assets acquired	$	94,179

The Partnership engaged a third-party valuation firm to assist in the valuation of Cascade Kelly's property and equipment related to the transloading assets. The Partnership's third-party valuation firm primarily used the replacement cost methodology to value property and equipment. The level of physical depreciation and other forms of depreciation was then quantified and deducted from the replacement cost to arrive at the fair value of the assets.

In regard to the ethanol plant, due to the nature of the assets acquired which are currently idle, the Partnership's third-party valuation firm provided fair value assessments using various valuation assumptions including the asset liquidation value, fair market value based on comparable sale transactions and the cost to replace the assets in their current physical state. In determining the fair value of the ethanol plant, management applied a weighting to each of the resulting valuations provided by the third-party valuation firm. Measurement period adjustments recorded in the fourth quarter include a $35.7 million reduction in the fair value of the ethanol plant as a result of the finalization of the third-party valuation.

The Partnership intends to make the capital improvements necessary to place the ethanol plant into service and expects the plant to be operational by 2016; therefore, as of December 31, 2013, the fair value of the ethanol plant is included in construction in process. After the plant has been successfully placed into service, depreciation will commence.

The leases assumed in the acquisition were determined to be at market value and, therefore, did not result in an asset or liability recorded in purchase accounting. The fair values of the remaining Cascade Kelly assets and liabilities noted above approximate their carrying values at February 15, 2013.

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 3. Business Combinations (continued)

reporting unit. The goodwill recognized is primarily attributed to the crude oil facility and the ethanol plant, which will strategically enhance the Partnership's network of origin to destination assets and extend the Partnership's virtual pipeline to the West Coast. The goodwill also reflects the synergies expected to be realized from Cascade Kelly's logistics services, and those services will benefit the Partnership's existing customers. The goodwill is deductible for income tax purposes.

2012 Acquisitions

Alliance Energy LLC—On March 1, 2012, pursuant to a Contribution Agreement between the Partnership and AE Holdings (the "Contribution Agreement"), the Partnership acquired from AE Holdings 100% of the outstanding membership interests in Alliance, a gasoline distributor and operator of gasoline stations and convenience stores. The aggregate purchase price of the acquisition was approximately $312.4 million, consisting of both cash and non-cash components. Alliance was an affiliate of the Partnership as Alliance was owned by AE Holdings which, on March 1, 2012, was 95% owned by members of the Slifka family. Both the Partnership and Alliance shared certain common directors.

The purchase price includes cash consideration of $181.9 million which was funded by the Partnership through additional borrowings under its revolving credit facility. The consideration also includes the issuance of 5,850,000 common units representing limited partner interests in the Partnership which had a fair value of $22.31 per unit on March 1, 2012, resulting in equity consideration of $130.5 million.

The purchase price for the acquisition was allocated to assets acquired and liabilities assumed based on their estimated fair values with the exception of environmental liabilities which were recorded on an undiscounted basis (see Note 9). The Partnership then allocated the purchase price in excess of net tangible assets acquired to identifiable intangible assets, based upon a valuation from an independent third party. Any excess purchase price over the fair value of the net tangible and intangible assets acquired was allocated to goodwill and assigned to the Gasoline Distribution and Station Operations reporting unit.

Mutual Oil—On December 12, 2012, the Partnership acquired six New England gasoline stations from Massachusetts based Mutual Oil Company ("Mutual Oil") for cash consideration of approximately $6.9 million. The purchase price was allocated to the assets acquired and liabilities assumed based on their estimated fair values at the date of the acquisition. The excess of cash consideration over the fair value of the net assets acquired of $5.7 million was allocated to goodwill, or $1.2 million. The acquisition was accounted for as a business combination. The acquisition, including the results of operations from December 12, 2012 to December 31, 2012, was not significant to the Partnership.

Supplemental Pro Forma Information

Revenues and net income included in the Partnership's consolidated operating results for Basin Transload from January 1, 2013 to February 1, 2013, the acquisition date, and for Cascade Kelly from January 1, 2013 to February 15, 2013, the acquisition date, were immaterial. Accordingly, the supplemental pro-forma information for the year ended December 31, 2013 is consistent with the amounts reported in the accompanying statement of income for the year ended December 31, 2013.

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 3. Business Combinations (continued)

The following unaudited pro forma information presents the consolidated results of operations of the Partnership as if the acquisitions of Basin Transload, Cascade Kelly and Alliance occurred at the beginning of each period presented, with pro forma adjustments to give effect to intercompany sales and certain other adjustments (in thousands, except per unit data):

	2012		2011

Sales	$	17,875,503	$	16,426,250
Net income	$	14,666	$	9,205
Net income per limited partner unit, basic and diluted	$	0.48	$	0.32

The Partnership's 60% interest in Basin Transload's sales and net loss included in the Partnership's consolidated operating results from February 1, 2013, the acquisition date, through the year ended December 31, 2013 were $8.7 million and $2.3 million, respectively. Cascade Kelly's sales and net loss included in the Partnership's consolidated operating results from February 15, 2013, the acquisition date, through the year ended December 31, 2013 were $11.0 million and $0.2 million, respectively.

The pro forma net income of the Partnership for the year ended December 31, 2012 does not reflect the impact of a $4.7 million Alliance receivable that the Partnership deemed to have a fair value of $0 at the acquisition date. Alliance's revenues and net income included in the Partnership's consolidated operating results from March 1, 2012, the acquisition date, through the year ended December 31, 2012 were $1.8 billion and $26.4 million, respectively.

Note 4. Derivative Financial Instruments

The following table presents the volume of activity related to the Partnership's derivative financial instruments at December 31, 2013:

	Units (1)			Unit of Measure

Futures Contracts
Long		13,411		Thousands of barrels
Short		(16,562	)	Thousands of barrels
Natural Gas Contracts
Long		6,958		Thousands of decatherms
Short		(6,958	)	Thousands of decatherms
Interest Rate Swaps	$	200.0		Millions of U.S. dollars
Interest Rate Cap	$	100.0		Millions of U.S. dollars
Foreign Currency Derivatives
Open Forward Exchange Contracts (2)	$	21.9		Millions of Canadian dollars
	$	20.6		Millions of U.S. dollars

(1): Number of open positions and gross notional amounts do not quantify risk or represent assets or liabilities of the Partnership, but are used in the calculation of daily cash settlements under the contracts.
(2): All-in forward rate Canadian dollars ("CAD") $1.0632 to USD $1.00.

Fair Value Hedges

The Partnership's futures contracts are settled daily; therefore, there was no corresponding asset or liability on the Partnership's consolidated balance sheet related to these contracts at December 31, 2013 and 2012. These contracts remain open until their contract end date. The daily settlement of these futures contracts is accomplished through the use of brokerage margin deposit accounts.

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 4. Derivative Financial Instruments (continued)

The following table presents the hedge ineffectiveness from derivatives involved in fair value hedging relationships recognized in the Partnership's consolidated statements of income for the years ended December 31 (in thousands):

		Amount of Gain (Loss) Recognized in Income on Derivatives

	Location of Gain (Loss) Recognized in Income on Derivatives	Amount of Gain (Loss) Recognized in Income on Derivatives
Derivatives in Fair Value Hedging Relationships	Location of Gain (Loss) Recognized in Income on Derivatives	2013			2012			2011
Futures contracts	Cost of sales	$	(18,231	)	$	(105,405	)	$	(77,855	)

		Amount of Gain (Loss) Recognized in Income on Hedged Items

	Location of Gain (Loss) Recognized in Income on Hedged Items	Amount of Gain (Loss) Recognized in Income on Hedged Items
Hedged Items in Fair Value Hedged Relationships		2013		2012		2011
Inventories	Cost of sales	$	17,949	$	105,664	$	78,166

Cash Flow Hedges

The following table presents the fair value of the Partnership's derivative instruments involved in cash flow hedging relationships and their location in the Partnership's consolidated balance sheets at December 31 (in thousands):

Derivatives Designated as Hedging Instruments	Balance Sheet Location	2013 Fair Value		2012 Fair Value

Asset derivatives
Interest rate cap	Other assets	$	25	$	35
Liability derivatives
Interest rate collar	Other long-term liabilities	$	—	$	1,868
Interest rate swaps	Other long-term liabilities		9,462		11,534


Total liability derivatives		$	9,462	$	13,402

The following table presents the amount of net gains and losses from derivatives involved in cash flow hedging relationships recognized in the Partnership's consolidated statements of income and partners' equity for the years ended December 31 (in thousands):

	Amount of Gain (Loss) Recognized in Other Comprehensive Income on Derivatives									Recognized in Income on Derivatives (Ineffectiveness Portion and Amount Excluded from Effectiveness Testing)

Derivatives in Cash Flow Hedging Relationship	2013			2012			2011			2013		2012		2011
Interest rate collar	$	1,868		$	1,949		$	2,225		$	—	$	—	$	—
Interest rate swaps		2,071			913			(5,151	)		—		—		—
Interest rate cap		(9	)		(271	)		(1,113	)		—		—		—


Total	$	3,930		$	2,591		$	(4,039	)	$	—	$	—	$	—

Ineffectiveness related to the interest rate collar and the interest rate swaps is recognized as interest expense and was immaterial for the years ended December 31, 2013, 2012 and 2011. The effective portion related to the interest rate collars that was originally reported in other comprehensive income and reclassified to earnings was $0, $2.5 million and $3.8 million for the years ended December 31, 2013, 2012 and 2011, respectively. None of the effective portion related to the interest rate cap that was originally reported in other comprehensive income was reclassified into earnings for the years ended December 31, 2013, 2012 and 2011.

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 4. Derivative Financial Instruments (continued)

Other Derivative Activity

Similar to the futures contracts used by the Partnership to hedge its inventory the Partnership uses future contracts to economically hedge forward purchase and sale contracts for which the Partnership does not take the normal purchase and sale exemption. Additionally, these futures contracts are settled daily and, accordingly, there was no corresponding asset or liability in the Partnership's consolidated balance sheets related to these contracts at December 31, 2013 and 2012. These contracts remain open until their contract end date. The daily settlement of these futures contracts is accomplished through the use of brokerage margin deposit accounts.

The following table summarizes the derivatives not designated by the Partnership as either fair value hedges or cash flow hedges and their respective fair values and location in the Partnership's consolidated balance sheets at December 31 (in thousands):

Summary of Other Derivatives	Item Pertains to		2013 Fair Value		2012 Fair Value

Asset Derivatives
Forward purchase commitments	Gasoline and Gasoline Blendstocks	(1)	$	14,119	$	131
	Distillates	(1)		2,232		—
	Residual Oil	(1)		34		285
	Crude Oil	(1)		13,693		15,127


Total forward purchase commitments				30,078		15,543
Forward sales commitments	Gasoline and Gasoline Blendstocks	(1)		1,486		30,928
	Distillates	(1)		797		—
	Residual Oil	(1)		655		—
	Crude Oil	(1)		383		—
	Natural Gas	(1)		12,608		1,591


Total forward sales commitments				15,929		32,519


Total forward fixed price contracts				46,007		48,062
Foreign currency forward contract	Foreign Denominated Sales	(2)		—		145


Total asset derivatives			$	46,007	$	48,207




Liability Derivatives
Forward purchase commitments	Gasoline and Gasoline Blendstocks	(3)	$	3,625	$	27,604
	Distillates	(3)		1,396		2,171
	Residual Oil	(3)		990		—
	Crude Oil	(3)		2,122		—
	Natural Gas	(3)		12,485		1,576


Total forward purchase commitments				20,618		31,351
Forward sales commitments	Gasoline and Gasoline Blendstocks	(3)		10,709		173
	Distillates	(3)		3,809		2,950
	Crude Oil	(3)		3,061		—


Total forward sales commitments				17,579		3,123


Total obligations on forward fixed price contracts				38,197		34,474
Foreign currency forward contract	Foreign Denominated Sales	(4)		16		—


Total liability derivatives			$	38,213	$	34,474

(1): Fair value of forward fixed price contracts
(2): Prepaid expenses and other current assets
(3): Obligations on forward fixed price contracts
(4): Accrued expenses and other current liabilities

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 4. Derivative Financial Instruments (continued)

The following table presents the amount of gains and losses from derivatives not involved in a hedging relationship recognized in the Partnership's consolidated statements of income for the years ended December 31 (in thousands):

		Amount of Gain (Loss) Recognized in Income on Derivatives

	Location of Gain (Loss) Recognized in Income on Derivatives	Amount of Gain (Loss) Recognized in Income on Derivatives
Derivatives Not Designated as Hedging Instruments	Location of Gain (Loss) Recognized in Income on Derivatives	2013			2012		2011
Product contracts	Cost of sales	$	11,819		$	17,164	$	9,517
Foreign currency contracts	Cost of sales		(162	)		145		—


Total		$	11,657		$	17,309	$	9,517

Credit Risk

The Partnership's derivative financial instruments do not contain credit risk related to other contingent features that could cause accelerated payments when these financial instruments are in net liability positions.

The Partnership is exposed to credit loss in the event of nonperformance by counterparties of forward purchase and sale commitments, futures contracts and swap agreements, but the Partnership has no current reason to expect any material nonperformance by any of these counterparties. Futures contracts, the primary derivative instrument utilized by the Partnership, are traded on regulated exchanges, greatly reducing potential credit risks. The Partnership utilizes primarily three clearing brokers, all major financial institutions, for all New York Mercantile Exchange ("NYMEX") and Chicago Mercantile Exchange ("CME") derivative transactions and the right of offset exists. Accordingly, the fair value of derivative instruments is presented on a net basis in the consolidated balance sheets. Exposure on forward purchase and sale commitments and swap agreements is limited to the amount of the recorded fair value as of the balance sheet dates.

Note 5. Income Taxes

GMG, a wholly owned subsidiary of the Partnership, is a taxable entity for federal and state income tax purposes. Current and deferred income taxes are recognized on the separate earnings of GMG, and the after-tax earnings of GMG are included in the consolidated earnings of the Partnership.

The following table presents a reconciliation of the difference between the statutory federal income tax rate and the effective income tax rate for the years ended December 31:



Federal statutory income tax rate	34.0%		34.0%		34.0%
State income tax rate, net of federal tax benefit	0.9%		7.8%		5.7%
Partnership income not subject to tax	(32.9%	)	(38.6%	)	(39.3%	)


Effective income tax rate	2.0%		3.2%		0.4%

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 5. Income Taxes (continued)

The following table presents the components of the provision for income taxes for the years ended December 31 (in thousands):

	2013			2012		2011

Current:
Federal	$	(59	)	$	71	$	—
State		542			289		68


Total current		483			360		68
Deferred:
Federal		442			940		67
State		(106	)		277		(67	)


Total deferred		336			1,217		—


Total	$	819		$	1,577	$	68

Significant components of current and long-term deferred taxes were as follows at December 31 (in thousands):

	2013					2012

	Current		Long-Term			Current		Long-Term
Deferred Income Tax Assets
Accounts receivable allowances	$	329	$	—		$	296	$	—
Environmental liability		—		4,792			—		4,958
Asset retirement obligation		—		646			—		660
Intangible assets		—		191			—		179
Capital lease		—		—			—		1,491
UNICAP		467		—			—		—
Other		24		—			9		—
Federal net operating loss carryforwards		—		9,810			—		5,625
State net operating loss carryforwards		—		1,537			—		1,107
Federal tax credit carryforward		—		115			—		174


Total deferred tax assets	$	820	$	17,091		$	305	$	14,194
Deferred Income Tax Liabilities
Property and equipment	$	—	$	(26,527	)	$	—	$	(21,112	)
Land		—		(4,353	)		—		(6,020	)


Total deferred tax liabilities	$	—	$	(30,880	)	$	—	$	(27,132	)


Net deferred tax assets (liabilities)	$	820	$	(13,789	)	$	305	$	(12,938	)

At December 31, 2013, the Partnership had federal and state net operating loss carryforwards of approximately $28.9 million and $31.3 million, respectively, which will begin to expire in 2030 and 2015, respectively. Utilization of the net operating loss carryforwards may be subject to annual limitations due to the ownership percentage change limitations provided by the Internal Revenue Code Section 382 and similar state provisions. In the event of a deemed change in control under Internal Revenue Code Section 382, an annual limitation imposed on the utilization of net operating losses may result in the expiration of all or a portion of the net operating loss carryforwards.

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 5. Income Taxes (continued)

At December 31, 2013, the Partnership had $8.6 million of net deferred tax liabilities relating to property and equipment, net operating loss carryforwards, tax credit carryforwards and other temporary differences, which are available to reduce income taxes in future years. A valuation allowance must be established when it is "more likely than not" that all or a portion of deferred tax assets will not be realized. A review of all available positive and negative evidence needs to be considered, including a company's performance, the market environment in which the company operates length of carryback and carryforward periods and projections of future operating results. The Partnership concluded, based on an evaluation of future operating results, that these assets are expected to be realized in a future period and, accordingly, no valuation allowance was required.

At December 31, 2013, the Partnership also had a $4.3 million, deferred tax liability relating to land. Land is an asset with an indefinite useful life and would not ordinarily serve as a source of income for the realization of deferred tax assets. This deferred tax liability will not reverse until some indefinite future period when the asset is either sold or written down due to impairment. Such taxable temporary differences generally cannot be used as a source of taxable income to support the realization of deferred tax assets relating to reversing deductible temporary differences, including loss carryforwards with expiration periods.

The Partnership recognizes deferred tax assets to the extent that the recoverability of these assets satisfy the "more likely than not" recognition criteria in accordance with the FASB's guidance regarding income taxes. Based upon its analysis, the Partnership has concluded it is more likely than not that it will have sufficient taxable income to utilize its deferred tax assets. Such future taxable income is derived from the reversal of existing taxable temporary differences.

The following presents a reconciliation of the differences between income before income tax expense and income subject to income tax expense for the years ended December 31 (in thousands):

	2013			2012			2011

Income before income tax expense	$	41,872		$	48,320		$	19,420
Non-taxable income		(41,640	)		(44,056	)		(18,817	)


Income subject to income tax expense	$	232		$	4,264		$	603

The Partnership made approximately $0.3 million, $0.9 million and $6,000 in income tax payments during 2013, 2012 and 2011, respectively.

GMG files income tax returns in the United States and various state jurisdictions. The Partnership is subject to income tax examinations by tax authorities for all years dated back to 2008.

At December 31, 2013 and 2012, the Partnership had no unrecognized tax benefits recorded in the financial statements. The Partnership performed an evaluation of all material tax positions for the tax years that remain subject to examination by major tax jurisdictions as of December 31, 2013 (tax years ended December 31, 2013, 2012 and 2011). Tax positions that do not meet the more-likely-than-not recognition threshold at the financial statement date may not be recognized or continue to be recognized under the accounting guidance for income taxes. Based on such evaluation, the Partnership concluded that there were no significant uncertain tax positions requiring adjustment regarding recognition in its financial statements as of December 31, 2013. The Partnership does not expect any significant changes in unrecognized tax benefits in 2014. Where required, the Partnership recognizes interest and penalties for uncertain tax positions in selling, general and administrative expenses.

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 6. Property and Equipment

Property and equipment consisted of the following at December 31 (in thousands):

	2013			2012

Buildings and improvements	$	601,900		$	498,984
Land		287,044			289,903
Fixtures and equipment		19,890			14,554
Construction in process		59,277			17,809
Capitalized internal use software		5,847			5,847


Total property and equipment		973,958			827,097
Less accumulated depreciation		(170,322	)		(114,775	)


Total	$	803,636		$	712,322

The increase of approximately $146.9 million in gross total property and equipment at December 31, 2013 was primarily due to the Partnership's acquisitions of its membership interests in Basin Transload and Cascade Kelly (see Note 3) and to additions related to the Partnership's gasoline stations and Albany, New York terminal.

At December 31, 2013, construction in process primarily included capitalized costs of approximately $30.5 million related to the Partnership's ethanol plant acquired from Cascade Kelly, $26.6 million in costs associated with our crude oil activities, primarily tank construction projects and a build-out project to increase the rail and receipt and throughput storage capacities at the Albany, New York terminal, construction costs at our compressed natural gas loading station in Bangor, Maine and various upgrades at certain other terminals and $2.2 million in costs related to the Partnership's gasoline stations.

At December 31, 2012, construction in process primarily included capitalized costs of approximately $8.5 million related to the construction of a rail-fed propane storage and distribution facility in Albany, New York and $7.6 million in costs related to the Partnership's gasoline stations.

As part of continuing operations, the Partnership may periodically divest certain gasoline stations. The gain (loss) on the sale, representing cash proceeds less net book value of assets at disposition, including an allocation of goodwill, is recorded in operating expenses. Gain (loss) on disposition of gasoline stations was not material for the years ended December 31, 2013, 2012 and 2011.

Depreciation

Depreciation expense allocated to cost of sales was approximately $55.6 million, $36.7 million and $24.4 million for the years ended December 31, 2013, 2012 and 2011, respectively.

Depreciation expense allocated to selling, general and administrative expenses was approximately $2.3 million, $1.8 million and $1.2 million for the years ended December 31, 2013, 2012 and 2011, respectively.

There were no fully depreciated assets written off for the years ended December 31, 2013 and 2012.

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 7. Goodwill and Intangible Assets

The following table presents a summary roll forward of the Partnership's goodwill at December 31, 2013 (in thousands):

	Goodwill at December 31, 2012		2013 Additions		Goodwill at December 31, 2013

Acquisition of Alliance (1)	$	31,151	$	—	$	31,151
Acquisition of gasoline stations from Mutual Oil Company (1)		1,175		—		1,175
Acquisition of 60% interest in Basin Transload (2)		—		86,064		86,064
Acquisition of Cascade Kelly(2)		—		35,688		35,688


Total	$	32,326	$	121,752	$	154,078

(1): Goodwill allocated to the GDSO reporting unit
(2): Goodwill allocated to the Wholesale reporting unit

Intangible assets consisted of the following (in thousands):

	Gross Carrying Amount		Accumulated Amortization			Net Intangible Assets		Amortization Period

At December 31, 2013
Intangible assets subject to amortization:
Terminalling services	$	26,365	$	(8,415	)	$	17,950	20 years
Customer relationships		43,986		(24,140	)		19,846	2-15 years
Supply contracts		39,646		(10,909	)		28,737	5-15 years
Brand incentive program		1,445		(641	)		804	5 years
Software		1,139		(1,139	)		—	5 years
Covenants not to compete		942		(942	)		—	3-5 years
Customer contracts		307		(307	)		—	2 years
Other intangible assets		779		(347	)		432	20 years


Total intangible assets	$	114,609	$	(46,840	)	$	67,769




At December 31, 2012
Intangible assets subject to amortization:
Terminalling services	$	26,365	$	(7,333	)	$	19,032	20 years
Customer relationships		17,986		(11,178	)		6,808	8-15 years
Supply contracts		39,646		(6,239	)		33,407	5-15 years
Brand incentive program		1,445		(403	)		1,042	5 years
Software		1,139		(1,139	)		—	5 years
Covenants not to compete		942		(932	)		10	3-5 years
Customer contracts		307		(307	)		—	2 years
Other intangible assets		616		(93	)		523	20 years


Total intangible assets	$	88,446	$	(27,624	)	$	60,822

The aggregate amortization expense was approximately $19.2 million, $7.0 million and $4.8 million for the years ended December 31, 2013, 2012 and 2011, respectively.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 7. Goodwill and Intangible Assets (continued)

The estimated annual intangible asset amortization expense for future years ending December 31 is as follows (in thousands):


2014	$	18,045
2015		9,886
2016		6,755
2017		6,419
2018		6,419
Thereafter		20,245


Total intangible assets	$	67,769

Note 8. Debt

Credit Agreement

On December 16, 2013, the Partnership entered into a Second Amended and Restated Credit Agreement (the "Credit Agreement"), which increased the Aggregate Commitments (as defined in the Credit Agreement) available under the Credit Agreement to $1.625 billion from $1.615 billion under the prior credit agreement. 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 the Partnership's 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 the Partnership may request on the same terms and conditions of its 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 the Partnership must be in a minimum amount of $5.0 million. The Partnership cannot provide assurance, however, that its lending group will agree to fund any request by the Partnership 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.

Pursuant to the Credit Agreement, and in connection with any agreement by and between a Loan Party and a Lender (as such terms are defined in the Credit Agreement) or affiliate thereof (an "AR Buyer"), a Loan Party may sell certain of its accounts receivables to an AR Buyer (the "Receivables Sales Agreement"). Also pursuant to the Credit Agreement, the Loan Parties are permitted to sell or transfer any account receivable to an AR Buyer only to the extent that (i) no Default or Event of

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 8. Debt (continued)

Default (as such terms are defined in the Credit Agreement) has occurred and is continuing or would exist after giving effect to any such sale or transfer; (ii) such accounts receivable are sold for cash; (iii) the cash purchase price to be paid to the selling Loan Party for each account receivable is not less than the amount of credit such Loan Party would have been able to get for such account receivable had such account receivable been included in the Borrowing Base (as defined in the Credit Agreement) or, to the extent such account receivable is not otherwise eligible to be included in the Borrowing Base, then the cash purchase price to be paid is not less than 85% of the face amount of such account receivable; (iv) such account receivable is sold pursuant to a Receivables Sales Agreement; (v) the Loan Parties have complied with the notice requirement set forth in the Credit Agreement; (vi) neither the AR Buyer nor the Administrative Agent has delivered any notice of a termination event; (vii) the aggregate amount of the accounts receivable sold to one or more AR Buyers which has not yet been collected will not exceed $75.0 million at any time; and (viii) the cash proceeds received from the applicable Loan Party in connection with such sale will be used to immediately repay any outstanding WC Loans (as defined in the Credit Agreement). To date, the level of receivables sold has not been significant, and the Partnership has accounted for such transfers as sales pursuant to ASC 860, "Transfers and Servicing." Due to the short - term nature of the receivables sold to date, no servicing obligation has been recorded because it would have been de minimus.

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 the Partnership's 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 the Partnership to seek waivers or amendments of covenants or alternative sources of financing or to reduce expenditures. The Partnership can provide no assurance that such waivers, amendments or alternative financing could be obtained or, if obtained, would be on terms acceptable to the Partnership.

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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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 8. Debt (continued)

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.

As of December 31, 2013, the Partnership had a two interest rate swaps and an interest rate cap, all of which were used to hedge the variability in interest payments under the Credit Agreement due to changes in LIBOR rates. See Notes 2 and 4 for additional information on these cash flow hedges.

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, the Partnership incurs a commitment fee on the unused portion of each facility under the Credit Agreement, ranging from 0.375% to 0.50% per annum.

The Partnership classifies a portion of its working capital revolving credit facility as a long-term liability because the Partnership has a multi-year, long-term commitment from its bank group. The long-term portion of the working capital revolving credit facility was $327.0 million and $340.8 million at December 31, 2013 and 2012, respectively, representing the amounts expected to be outstanding during the entire year. In addition, the Partnership classifies a portion of its working capital revolving credit facility as a current liability because it repays amounts outstanding and reborrows funds based on its working capital requirements. The current portion of the working capital revolving credit facility was approximately $0 and $83.7 million at December 31, 2013 and 2012, respectively, representing the amounts the Partnership expects to pay down during the course of the year.

As of December 31, 2013, the Partnership had total borrowings outstanding under the Credit Agreement of $761.7 million, including $434.7 million outstanding on the revolving credit facility. In addition, the Partnership 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.

The Credit Agreement is secured by substantially all of the assets of the Partnership and the Partnership's wholly-owned subsidiaries and is guaranteed by the Partnership and its subsidiary, Bursaw Oil LLC. The Credit Agreement imposes certain requirements on the borrowers including, for example, a prohibition against distributions if any potential default or Event of Default (as defined in the Credit Agreement) would occur as a result thereof, and certain limitations on the Partnership's ability to grant liens, make certain loans or investments, incur additional indebtedness or guarantee other indebtedness, make any material change to the nature of the Partnership's business or undergo a fundamental

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 8. Debt (continued)

change, make any material dispositions, acquire another company, enter into a merger, consolidation, sale leaseback transaction or purchase of assets, or make capital expenditures in excess of specified levels.

The Credit Agreement imposes financial covenants that require the Partnership 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. The Partnership was 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 the Partnership to its unitholders to the amount of Available Cash (as defined in the Partnership's partnership agreement).

8.00% Senior Notes

On February 14, 2013, the Partnership 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 the Partnership 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 the Partnership of approximately $67.9 million. Additionally, the Partnership 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, the Partnership used the net proceeds from the offering, after paying fees and offering expenses, to finance a portion of its 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 the Partnership, its 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. The Partnership 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 the Partnership 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, the Partnership, its 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 the

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 8. Debt (continued)

Partnership or any Restricted Subsidiary (as defined in the February Indenture) of the Partnership that the Partnership 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 the Partnership and its 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 the Partnership's Consolidated Net Tangible Assets (as defined in the February Indenture).

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

7.75% Senior Notes

On December 23, 2013, the Partnership 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 the Partnership 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 the Partnership of $80.0 million. Additionally, the Partnership separately paid fees and offering expenses. The Partnership 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 the Partnership, its 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 will be paid on the 7.75% Notes semi-annually on December 23 and June 23 of each year, beginning on June 23, 2014.

The Partnership 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 the Partnership 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.

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 8. Debt (continued)

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

Line of Credit

Deferred Financing Fees

The Partnership incurs bank fees related to its Credit Agreement and other financing arrangements. These deferred financing fees are amortized over the life of the Credit Agreement or senior notes. The Partnership 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.

Note 9. Environmental Liabilities and Renewable Identification Numbers (RINs)

Environmental Liabilities

The Partnership owns or leases properties where refined petroleum products, renewable fuels and crude oil are being or may have been handled. These properties and the refined petroleum products, renewable fuels and crude oil handled thereon may be subject to federal and state environmental laws and regulations. Under such laws and regulations, the Partnership could be required to remove or remediate containerized hazardous liquids or associated generated wastes (including wastes disposed of or abandoned by prior owners or operators), to clean up contaminated property arising from the release of liquids or wastes into the environment, including contaminated groundwater, or to implement best management practices to prevent future contamination.

The Partnership maintains insurance of various types with varying levels of coverage that it considers adequate under the circumstances to cover its operations and properties. The insurance policies are subject to deductibles that the Partnership considers reasonable and not excessive. In addition, the Partnership has entered into indemnification agreements with various sellers in conjunction with several of its acquisitions. Allocation of environmental liability is an issue negotiated in connection with each of the Partnership's acquisition transactions. In each case, the Partnership makes an assessment of potential environmental liability exposure based on available information. Based on that assessment and relevant economic and risk factors, the Partnership determines whether to, and the extent to which it will, assume liability for existing environmental conditions.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 9. Environmental Liabilities and Renewable Identification Numbers (RINs) (continued)

In connection with the December 2012 acquisition of six New England gasoline stations from Mutual Oil (see Note 3), the Partnership assumed certain environmental liabilities, including certain ongoing remediation efforts. As a result, the Partnership recorded, on an undiscounted basis, a total environmental liability of approximately $0.6 million.

In connection with the March 2012 acquisition of Alliance (see Note 3), the Partnership 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, the Partnership's 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, the Partnership recorded, on an undiscounted basis, total environmental liabilities of approximately $16.1 million.

In connection with the September 2010 acquisition of retail gasoline stations from ExxonMobil, the Partnership 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, the Partnership's 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, the Partnership recorded, on an undiscounted basis, total environmental liabilities of approximately $30.0 million.

In connection with the June 2010 acquisition of three refined petroleum products terminals in Newburgh, New York, the Partnership assumed certain environmental liabilities, including certain ongoing remediation efforts. As a result, the Partnership recorded, on an undiscounted basis, a total environmental liability of approximately $1.5 million.

In connection with the November 2007 acquisition of ExxonMobil's Glenwood Landing and Inwood, New York terminals, the Partnership 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, the Partnership recorded, on an undiscounted basis, total environmental liabilities of approximately $1.2 million.

In connection with the May 2007 acquisition of ExxonMobil's Albany and Newburgh, New York and Burlington, Vermont terminals, the Partnership 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, the Partnership recorded, on an undiscounted basis, total environmental liabilities of approximately $8.0 million.

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 9. Environmental Liabilities and Renewable Identification Numbers (RINs) (continued)

The following table presents a summary roll forward of the Partnership's environmental liabilities at December 31, 2013 (in thousands):

Environmental Liability Related to:	Balance at December 31, 2012		Payments in 2013			Dispositions 2013			Other Adjustments			Balance at December 31, 2013

ExxonMobil Gasoline Stations	$	26,610	$	(1,267	)	$	(595	)	$	(3	)	$	24,745
Alliance Gasoline Stations		14,984		(754	)		(750	)		441			13,921
Mutual Oil		625		—			—			—			625
Newburgh		1,500		—			—			—			1,500
Glenwood Landing and Inwood		347		(46	)		—			—			301
Albany		106		(59	)		—			—			47


Total environmental liabilities	$	44,172	$	(2,126	)	$	(1,345	)	$	438		$	41,139




Current portion	$	4,341										$	3,377
Long-term portion		39,831											37,762


Total environmental liabilities	$	44,172										$	41,139

The Partnership's estimates used in these environmental liabilities are based on all known facts at the time and its assessment of the ultimate remedial action outcomes. Among the many uncertainties that impact the Partnership's estimates are the necessary regulatory approvals for, and potential modification of, its remediation plans, the amount of data available upon initial assessment of the impact of soil or water contamination, changes in costs associated with environmental remediation services and equipment, relief of obligation through divestures of sites and the possibility of existing legal claims giving rise to additional claims. Dispositions generally represent relief of legal obligation through the sale of the related property. Other adjustments generally represent changes in estimates for existing obligations or obligations associated with new sites. Therefore, although the Partnership believes that these environmental liabilities are adequate, no assurances can be made that any costs incurred in excess of these environmental liabilities or outside of indemnifications or not otherwise covered by insurance would not have a material adverse effect on the Partnership's financial condition, results of operations or cash flows.

Renewable Identification Numbers (RINs)

A RIN is a serial number assigned to a batch of biofuel for the purpose of tracking its production, use, and trading as required by the EPA Renewable Fuel Standard that originated with the Energy Policy Act of 2005. To evidence that the required volume of renewable fuel is blended with gasoline, obligated parties must retire sufficient RINs to cover their RVO. The Partnership's EPA obligations relative to renewable fuel reporting are largely limited to the foreign gasoline that the Partnership may choose to import. As a wholesaler of transportation fuels through its terminals, the Partnership separates RINs from renewable fuel through blending with gasoline and can use those separated RINs to settle its RVO. While the annual compliance period for a RVO is a calendar year, the settlement of the RVO can occur more than one year after the close of the compliance period, upon certain deferral elections.

The Partnership's Wholesale segment's operating results are sensitive to the timing associated with its RIN position relative to its RVO at a point in time, and the Partnership may recognize a mark-to-market liability for a shortfall in RINs at the end of each reporting period. To the extent the

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 9. Environmental Liabilities and Renewable Identification Numbers (RINs) (continued)

Partnership does not have a sufficient number of RINs to satisfy the obligation as of the balance sheet date, the Partnership charges cost of sales for such deficiency based on the market price of the RINs as of the balance sheet date, and records a liability representing the Partnership's obligation to purchase RINs. At December 31, 2013, the Partnership's RVO Deficiency was $13.1 million. The Partnership's RVO Deficiency was immaterial at December 31, 2012.

The Partnership may enter into RIN forward commitments. At December 31, 2013, the Partnership had forward sales contracts that were fixed at a price below the RIN spot rate. Accordingly, the Partnership accrued for the loss of these firm non-cancellable purchase commitments which amounted to approximately $6.2 million at December 31, 2013. The loss on RIN forward commitments was immaterial at December 31, 2012.

Note 10. Trustee Taxes and Accrued Expenses and Other Current Liabilities

Accrued expenses and other current liabilities consisted of the following at December 31 (in thousands):

	2013		2012

Barging transportation, product storage and other ancillary cost accruals	$	24,022	$	47,837
Employee compensation		12,735		13,716
Accrued interest		3,331		1,090
RIN and RVO deficiency		13,068		—
RIN loss on forward commitments		6,166		—
Other		6,641		9,889


Total	$	65,963	$	71,442

Employee compensation consisted of bonuses, vacation and other salary accruals. Ancillary costs consisted of cost accruals related to product expediting and storage.

In addition, the Partnership had trustee taxes payable of $80.2 million at December 31, 2013, which consisted of $55.4 million related to an ethanol credit and $24.8 million in various pass-through taxes collected from customers on behalf of taxing authorities. Trustee taxes payable at December 31, 2012 of $91.5 million consisted of $56.3 million related to an ethanol credit and $35.2 million in various pass-through taxes collected from customers on behalf of taxing authorities.

Note 11. Employee Benefit Plans with Related Party

The Partnership sponsors and maintains the Global Partners LP 401(k) Savings and Profit Sharing Plan (the "Global 401(k) Plan), a qualified defined contribution plan. Eligible employees may elect to contribute up to 100% of their eligible compensation to the Global 401(k) Plan for each payroll period, subject to annual dollar limitations which are periodically adjusted by the IRS. The General Partner makes safe harbor matching contributions to the Global Partners 401(k) Plan equal to 100% of the participant's elective contributions that do not exceed 3% of the participant's eligible compensation and 50% of the participant's elective contributions that exceed 3% but do not exceed 5% of the participant's eligible compensation. The General Partner also makes discretionary non-matching contributions for certain groups of employees in amounts up to 2% of eligible compensation. Profit-sharing contributions may also be made at the sole discretion of the General Partner's board of directors.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 11. Employee Benefit Plans with Related Party (continued)

GMG sponsors and maintains the Global Montello Group Corp. 401(k) Savings and Profit Sharing Plan (the "GMG 401(k) Plan), a qualified defined contribution plan. Eligible employees may elect to contribute up to 100% of their eligible compensation to the 401(k) Savings and Profit Sharing Plan for each payroll period, subject to annual dollar limitations which are periodically adjusted by the IRS. GMG makes safe harbor matching contributions to the 401(k) Savings and Profit Sharing Plan equal to 100% of the participant's elective contributions that do not exceed 3% of the participant's eligible compensation and 50% of the participant's elective contributions that exceed 3% but do not exceed 5% of the participant's eligible compensation. Profit-sharing contributions may also be made at the sole discretion of GMG's board of directors.

The Global 401(k) Plan and the GMG 401(k) Plan collectively had expenses of approximately $1.8 million, $1.6 million and $1.1 million for the years ended December 31, 2013, 2012 and 2011, respectively, which are included in selling, general and administrative expenses in the accompanying statements of income.

In addition, the General Partner sponsors and maintains the Global Partners LP Pension Plan (the "Global Pension Plan)," a qualified defined benefit pension plan. Effective December 31, 2009, the Global Pension Plan was amended to freeze participation and benefit accruals. In order to reduce the adverse effects of the pension freeze on employees with substantial service who may not have time to replace future pension accruals with retirement savings before reaching the normal retirement age of 65, employees meeting certain age and service requirements received increased benefits, including under the Global 401(k) Plan, effective December 31, 2009.

GMG sponsors and maintains the Global Montello Group Corp. Pension Plan (the "GMG Pension Plan"), a qualified defined benefit pension plan. On March 15, 2012, the GMG Pension Plan was amended to freeze participation and benefit accruals. In order to reduce the adverse effects of the pension freeze on employees with substantial service who may not have time to replace future pension accruals with retirement savings before reaching the normal retirement age of 65, employees meeting certain age and service requirements received increased benefits, including under the Global 401(k) Plan and the GMG 401(k) Plan, effective in 2012. As a result of the freeze, the Partnership recognized a curtailment gain of approximately $0.5 million which was recorded as an offset to selling, general and administrative expenses in the accompanying consolidated statement of income for the year ended December 31, 2012. The curtailment gain consisted of approximately $2.8 million in a change in benefit obligation and approximately $2.3 million in an unrecognized net actuarial loss.

The following table presents each plan's funded status and the total amounts recognized in the Partnership's consolidated balance sheets at December 31 (in thousands):

	December 31, 2013

	Global Pension Plan		GMG Pension Plan		Total
Projected benefit obligation	$	15,057	$	4,189	$	19,246
Fair value of plan assets		14,435		3,832		18,267


Net unfunded pension liability	$	622	$	357	$	979

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Note 11. Employee Benefit Plans with Related Party (continued)

	December 31, 2012

	Global Plan		GMG Plan		Total
Projected benefit obligation	$	17,317	$	5,779	$	23,096
Fair value of plan assets		12,980		4,178		17,158


Net unfunded pension liability	$	4,337	$	1,601	$	5,938

For both the Global Pension Plan and the GMGC Pension Plan (collectively, the "Pension Plans"), the total change in the net unfunded pension liability in 2013 was $5.0 million, of which $4.4 million has been recorded in other comprehensive income. Total actual return on plan assets was $2.7 million and $1.7 million in 2013 and 2012, respectively. The total net periodic pension costs related to the Pension Plans were $32,000, $75,000 and $83,000 in 2013, 2012 and 2011, respectively.

The discount rates for 2013 and 2012 were selected by performing a cash flow/bond matching analysis based on the Citigroup Above-Median Pension Discount Curve for December 2013 and 2012, respectively. The discount rate for each of the Pension Plans was 4.4% and 3.5% in 2013 and 2012, respectively. The expected long-term rate of return on plan assets is determined by using each plan's respective target allocation and historical returns for each asset class. The expected long-term rate of return for the Global Pension Plan was 7.5% and 8.0% in 2013 and 2012, respectively. The expected long-term rate of return for the GMG Pension Plan was 7.0% and 8.0% in 2013 and 2012, respectively.

The fundamental investment objective of each of the Pension Plans is to provide a rate of return sufficient to fund the retirement benefits under the applicable Pension Plan at a reasonable cost to the applicable plan sponsor. At a minimum, the rate of return should equal or exceed the discount rate assumed by the Pension Plan's actuaries in projecting the funding cost of the Pension Plan under the applicable Employee Retirement Income Security Act ("ERISA") standards. To do so, the General Partner's Pension Committee (the "Committee") may appoint one or more investment managers to invest all or portions of the assets of the Pension Plans in accordance with specific investment guidelines, objectives, standards and benchmarks.

The cost of annual contributions to the Pension Plans is not significant to the General Partner, the Partnership or its subsidiaries. Total contributions made by the General Partner, the Partnership and its subsidiaries to the Pension Plans were $0.5 million in 2013, $0.5 million in 2012 and, in 2011, before the GMG Pension Plan was sponsored by a subsidiary of the Partnership, $1.7 million for the Global Pension Plan.

Note 12. Long-Term Incentive Plan

The General Partner has a Long-Term Incentive Plan ("LTIP") whereby 564,242 common units were initially authorized for issuance. On June 22, 2012, the Partnership's common unitholders approved an amendment and restatement of the LTIP (the "Restated LTIP"). The Restated LTIP: (i) increases the number of common units available for delivery with respect to awards under the LTIP so that, effective June 22, 2012 a total of 4,300,000 common units are available for delivery with respect to awards under the Restated LTIP, (ii) adds a prohibition on repricing of unit options and unit appreciation rights without approval of the Partnership's unitholders, except in the case of adjustments implemented to reflect certain Partnership transactions, (iii) adds a prohibition on granting unit options or unit appreciation rights with an exercise price less than the fair market value of a common unit on

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Note 12. Long-Term Incentive Plan (continued)

the grant date (other than "substitute awards" granted in substitution for similar awards held by individuals who become employees, consultants and directors of the Partnership or one of its affiliates as a result of a merger, consolidation or acquisition by the Partnership or its affiliate of another entity or the assets of another entity), (iv) permits the granting of fully-vested common units and (v) incorporates certain other non-material ministerial changes. Any units delivered pursuant to an award under the Restated LTIP may be acquired in the open market, issued by the Partnership, or any combination of the foregoing. The Restated LTIP provides for awards to employees, consultants and directors of the General Partner and employees and consultants of affiliates of the Partnership who perform services for the Partnership. The Restated LTIP allows for the award of options, unit appreciation rights, restricted units, phantom units, distribution equivalent rights, unit awards and substitute awards.

Phantom Unit Awards

On June 27, 2013, the Compensation Committee of the board of directors of the General Partner granted a total of 498,112 phantom units under the Restated LTIP to certain employees and non-employee directors of the General Partner. In connection with the awards, grantees who are employees entered into various forms of a Confidentiality, Non-Solicitation, and Non-Competition Agreement with the General Partner. The Partnership currently intends and reasonably expects to issue and deliver the common units upon vesting.

The awards granted to employees, with one exception, will vest on a cumulative basis as follows, subject to continued employment: 33¹/3% on July 1, 2017, 66²/3% on July 1, 2018 and 100% on July 1, 2019. The phantom unit award to one employee will vest on a cumulative basis as follows, subject to continued employment: 33¹/3% on December 31, 2014, 66²/3% on December 31, 2015 and 100% on December 31, 2016. The awards granted to the non-employee directors will vest on a cumulative basis as follows: 33¹/3% on December 31, 2014, 66²/3% on December 31, 2015 and 100% on December 31, 2016.

Accounting guidance for share-based compensation requires that a non-vested equity share unit awarded to an employee is to be measured at its fair value as if it were vested and issued on the grant date. The fair value of the award at the June 27, 2013 grant date approximated the fair value of the Partnership's common unit at that date.

Compensation cost for an award of share-based employee compensation classified as equity, as is the case of the Partnership's award, is recognized over the requisite service period. The requisite service period for the Partnership is from June 27, 2013, the grant date, through the vesting dates described above. The Partnership will recognize as compensation expense for the awards granted to employees and non-employee directors the value of the portion of the award that is ultimately expected to vest over the requisite service period on a straight-line basis. In accordance with the guidance issued for share-based compensation, the Partnership estimated forfeitures at the time of grant. Such estimates, which were based on the Partnership's service history, will be revised, if necessary, in subsequent periods if actual forfeitures differ from estimates. The Partnership recorded compensation expense related to these awards of approximately $1.7 million for the year ended December 31, 2013, which is included in selling, general and administrative expenses in the accompanying consolidated statement of income. The total compensation cost related to the non-vested awards not yet recognized

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 12. Long-Term Incentive Plan (continued)

at December 31, 2013 was approximately $17.8 million and is expected to be recognized ratably over the remaining requisite service period.

Previously Granted Phantom Unit Awards

The Partnership granted phantom unit awards in 2009 and 2008 for which it recorded compensation expense of approximately $0.1 million and $0.4 million for the years ended December 31, 2012 and 2011, respectively, which are included in selling, general and administrative expenses in the accompanying consolidated statements of income. The total compensation cost related to the non-vested awards not yet recognized at December 31, 2013 was $0.

Status of Non-Vested Units

The following table presents a summary of the status of the non-vested phantom units:

			Weighted Average Grant Date Fair Value

Outstanding non-vested units at December 31, 2012	138,889		$	13.01
Granted	498,112			39.29
Vested	(138,889	)		13.01
Forfeited	—			—


Outstanding non-vested units at December 31, 2013	498,112		$	39.29

Repurchase Program

In May 2009, the board of directors of the General Partner authorized the repurchase of the Partnership's common units (the "Repurchase Program") for the purpose of meeting the General Partner's anticipated obligations to deliver common units under the LTIP and meeting the General Partner's obligations under existing employment agreements and other employment related obligations of the General Partner (collectively, the "General Partner's Obligations"). The General Partner is currently authorized to acquire up to 742,427 of its common units in the aggregate over an extended period of time, consistent with the General Partner's Obligations. Common units of the Partnership 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. Since the Repurchase Program was implemented, the General Partner repurchased 495,414 common units pursuant to the Repurchase Program for approximately $12.2 million, of which approximately $4.6 million was purchased in 2013.

At December 31, 2013 and 2012, common units outstanding as reported in the accompanying consolidated financial statements excluded 169,816 and 119,915 common units, respectively, held on behalf of the Partnership pursuant to its Repurchase Program and for future satisfaction of the General Partner's Obligations.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 13. Commitments and Contingencies

The Partnership is subject to contingencies, including legal proceedings and claims arising out of the normal course of business that cover a wide range of matters, including, among others, environmental matters and contract and employment claims.

Leases of Office Space and Computer Equipment

The Partnership has future commitments, principally for office space and computer equipment, under the terms of operating lease arrangements. The following provides total future minimum payments under leases with non-cancellable terms of one year or more at December 31, 2013 (in thousands):


2014	$	2,364
2015		2,782
2016		2,965
2017		2,728
2018		2,768
Thereafter		18,670


Total	$	32,277

Total rent expense under the operating lease arrangements amounted to approximately $2.7 million, $2.7 million and $2.3 million for the years ended December 31, 2013, 2012 and 2011, respectively. The Partnership also received lease income from office space leased at one of its owned terminals for $0.2 million per year through May 2013. Effective June 1, 2013, the terms of this lease were amended to, in part, reduce the lease amount to approximately $0.1 million per year through January 2019.

The Partnership also leases certain equipment under capital lease agreements, for which the net book value was approximately $0.8 million and $0.5 million at December 31, 2013 and 2012, respectively. Depreciation expense for equipment under the capital leases was approximately $275,000, $245,000 and $245,000 for the years ended December 31, 2013, 2012 and 2011, respectively. The following provides the future minimum payments for capital lease obligations at December 31, 2013 (in thousands):


2014	$	176
2015		176
2016		176
2017		292
2018		6


Total	$	826

Terminal and Throughput Leases

The Partnership is a party to terminal and throughput lease arrangements with certain counterparties at various unrelated oil terminals. Certain arrangements have minimum usage

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 13. Commitments and Contingencies (continued)

requirements. The following provides future minimum lease and throughput commitments under these arrangements with non-cancellable terms of one year or more at December 31, 2013 (in thousands):


2014	$	12,222
2015		7,319
2016		6,961
2017		3,406
2018		839
Thereafter		168


Total	$	30,915

Total rent expense reflected in cost of sales related to these operating leases were approximately $35.5 million, $36.5 million and $26.0 million for the years ended December 31, 2013, 2012 and 2011, respectively.

Leases of Gasoline Stations

The Partnership has gasoline station lease arrangements at various gasoline stations. The Partnership also leases gasoline stations, primarily land and buildings, under operating leases with various expiration dates. The following provides future minimum lease commitments under these arrangements with non-cancellable terms of one year or more at December 31, 2013 (in thousands):


2014	$	17,049
2015		16,597
2016		16,028
2017		14,254
2018		12,706
Thereafter		93,120


Total	$	169,754

Total expenses under these operating lease arrangements amounted to approximately $17.7 million, $8.5 million and $3.3 million for the years ended December 31, 2013, 2012 and 2011, respectively. The increase in expense for 2013 compared to 2012 is due to the Partnership's agreement with Getty Realty Corp. and to the inclusion of Alliance for the full year of 2013 compared to ten months in 2012. The increase in expense for 2012 compared to 2011 is due to the acquisition of Alliance.

Dealer Leases of Gasoline Stations

The Partnership leases gasoline stations and certain equipment to gasoline station operators under operating leases with various expiration dates. The aggregate carrying value of the leased gasoline stations and equipment at December 31, 2013 was $213.0 million, net of accumulated depreciation of

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 13. Commitments and Contingencies (continued)

approximately $26.3 million. The following provides future minimum rental income under non-cancellable operating leases associated with these properties at December 31, 2013 (in thousands):


2014	$	37,417
2015		18,714
2016		8,007
2017		938
2018		392
Thereafter		43


Total	$	65,511

Total rental income, which includes reimbursement of utilities and property taxes in certain cases, amounted to approximately $41.3 million and $31.8 million for the years ended December 31, 2013 and 2012, respectively.

Leases of Railcars

The Partnership leases railcars through various lease arrangements with various expiration dates. The following provides future minimum lease commitments under these arrangements with non-cancellable terms of one year or more at December 31, 2013 (in thousands):


2014	$	55,713
2015		65,072
2016		64,909
2017		49,365
2018		40,409
Thereafter		27,193


Total	$	302,661

Total expenses under these operating lease arrangements amounted to approximately $28.9 million and $3.5 million for the years ended December 31, 2013 and 2012, respectively. The increase in expenses was due to the Partnership leasing significantly more rail cars in 2013 due to the growth in the Partnership's crude oil activities.

Purchase Commitments

The minimum volume purchase requirements for 2014 under the Partnership's existing supply agreements are approximately 845 million gallons. The Partnership purchased approximately 1.3 billion, 1.2 billion and 1.4 billion gallons of product under the Partnership's existing supply agreements for $3.6 billion, $3.3 billion and $4.0 billion in 2013, 2012 and 2011, respectively, which included fulfillment of the minimum purchase obligation under these commitments.

The Partnership has minimum retail gasoline volume purchase requirements with various unrelated parties. These gallonage requirements are purchased at the fair market value of the product at the time of delivery. Should these gallonage requirements not be achieved, the Partnership may be liable to pay penalties to the appropriate supplier. As of December 31, 2013, the Partnership has fulfilled all

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 13. Commitments and Contingencies (continued)

gallonage commitments. The following provides minimum volume purchase requirements at December 31, 2013 (in thousands of gallons):


2014			209,850
2015			198,079
2016			158,645
2017			112,526
2018			107,400
Thereafter			751,800


Total			1,538,300

Brand Fee Agreement

The Partnership entered into a brand fee agreement with ExxonMobil which entitles the Partnership to operate its retail gasoline stations under the Mobil-branded trade name and related trade logos. The fees, which are based upon an estimate of the volume of gasoline and diesel to be sold at the acquired gasoline stations, are due on a monthly basis. The following provides total future minimum payments under the agreement with non-cancellable terms of one year or more at December 31, 2013 (in thousands):


2014	$	9,000
2015		9,000
2016		9,000
2017		9,000
2018		9,000
Thereafter		58,500


Total	$	103,500

Total expenses reflected in cost of sales related this agreement were approximately $9.0 million for each of the years ended December 31, 2013, 2012 and 2011.

Port of St. Helens Agreements—Land and Equipment

Commencing in 2013, the Partnership leases mobile equipment under non-cancellable operating lease arrangements and has a continuing operating lease with the Port of St. Helens. The following provides total future minimum payments under these operating leases with initial terms one year or more at December 31, 2013 (in thousands):


2014	$	183
2015		183
2016		183
2017		183
2018		183
Thereafter		8,718


Total	$	9,633

Total rental expense was approximately $180,000 for the year ended December 31, 2013.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 13. Commitments and Contingencies (continued)

Port of St. Helens Agreements—Access Rights Agreement

Commencing in 2013, the Partnership is obligated to pay the Port of St Helens for access rights to a rail spur located at the Partnership's crude oil and ethanol plant facility in Oregon. The following provides total future minimum payments under the agreement with initial terms one year or more at December 31, 2013 (in thousands):


2014	$	230
2015		230
2016		230
2017		230
2018		230
Thereafter		3,201


Total	$	4,351

Other Commitment

In March 2013, the Partnership entered into a pipeline connection agreement with Tesoro Logistics ("Tesoro") whereby Tesoro would build, own and operate a seven-mile pipeline lateral from its Lignite, North Dakota crude oil station to the Partnership's 100,000 barrel crude oil storage tank at the Basin Transload facility in Columbus, North Dakota. In connection with this agreement, the Partnership is committed to a minimum take-or-pay throughput commitment of approximately $13.0 million over a 5-year period beginning after the commissioning of the pipeline, which occurred in August of 2013. At December 31, 2013, the remaining commitment on the take-or-pay commitment was approximately $11.8 million.

Environmental Liabilities

Please see Note 9 for a discussion of the Partnership's environmental liabilities.

Legal Proceedings

Please see Note 20 for a discussion of the Partnership's legal proceedings.

Note 14. Partners' Equity, Allocations and Cash Distributions

Units Outstanding

Partners' equity at December 31, 2013 consisted of 27,430,563 common units outstanding (including 11,599,336 common units held by affiliates of the General Partner, including directors and executive officers), collectively representing a 99.17% limited partner interest in the Partnership, and 230,303 general partner units representing a 0.83% general partner interest in the Partnership.

Partners' equity at December 31, 2013 and 2012 excluded common units outstanding of 169,816 and 119,915 common units, respectively, held pursuant to the Repurchase Program and for future satisfaction of the General Partner's Obligations. See Note 12, "Long-Term Incentive Plan—Repurchase Program."

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 14. Partners' Equity, Allocations and Cash Distributions (continued)

Common Units

The common units have limited voting rights as set forth in the Partnership's partnership agreement.

Pursuant to the Partnership's partnership agreement, if at any time the General Partner and its affiliates own more than 80% of the common units outstanding, the General Partner has the right, but not the obligation, to "call" or acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market value. The General Partner may assign this call right to any of its affiliates or to the Partnership.

Subordinated Units

On February 16, 2011, based upon satisfying certain distribution and performance tests provided in the Partnership's partnership agreement, all 5,642,424 subordinated units have converted to common units.

General Partner Units

The Partnership's general partner interest is represented by general partner units. The General Partner is entitled to a percentage (equal to the general partner interest) of all cash distributions of available cash on all common units. The Partnership's partnership agreement sets forth the calculation to be used to determine the amount and priority of cash distributions that the common unitholders, holders of the incentive distribution rights and the General Partner will receive.

The Partnership's general partner interest has the management rights as set forth in the Partnership's partnership agreement.

Incentive Distribution Rights

Incentive distribution rights represent the right to receive an increasing percentage of quarterly distributions of available cash from distributable cash flow after the target distribution levels have been achieved, as defined in the Partnership's partnership agreement. The General Partner currently holds all of the incentive distribution rights, but may transfer these rights separately from its general partner interest, subject to restrictions in the Partnership's partnership agreement.

Allocations of Net Income

Net income is allocated between the General Partner and the common unitholders in accordance with the provisions of the Partnership's partnership agreement. Net income is generally allocated first to the General Partner and the common unitholders in an amount equal to the net losses allocated to the General Partner and the common unitholders in the current and prior tax years under the Partnership's partnership agreement. The remaining net income is allocated to the General Partner and the common unitholders in accordance with their respective percentage interests of the general partner units and common units.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 14. Partners' Equity, Allocations and Cash Distributions (continued)

Cash Distributions

The Partnership intends to consider regular 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. The Credit Agreement prohibits the Partnership from making cash distributions if any potential default or Event of Default, as defined in the Credit Agreement, occurs or would result from the cash distribution.

Within 45 days after the end of each quarter, the Partnership will distribute all of its Available Cash (as defined in its 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 the General Partner to provide for the proper conduct of the Partnership's business, to comply with applicable law, any of the Partnership's debt instruments, or other agreements or to provide funds for distributions to unitholders and the General Partner for any one or more of the next four quarters.

The Partnership 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 the Partnership distributes 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.

As holder of the IDRs, the General Partner is entitled to incentive distributions if the amount that the Partnership distributes 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	%

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 14. Partners' Equity, Allocations and Cash Distributions (continued)

The Partnership paid the following cash distributions during 2013, 2012 and 2011 (in thousands, except per unit data):

Cash Distribution Payment Date	Per Unit Cash Distribution		Common Units		Subordinated Units		General Partner		Incentive Distribution		Total Cash Distribution

2011
02/14/11 (1)(2)	$	0.5000	$	6,647	$	2,821	$	115	$	108	$	9,691
05/13/11 (2)		0.5000		10,790		N/A		116		122		11,028
08/12/11 (2)		0.5000		10,790		N/A		116		122		11,028
11/14/11 (2)		0.5000		10,790		N/A		116		122		11,028
2012
02/14/12 (2)(3)	$	0.5000	$	10,790		N/A	$	116	$	122	$	11,028
05/14/12 (2)(4)		0.5000		13,716		N/A		115		155		13,986
08/14/12 (5)		0.5250		14,401		N/A		121		259		14,781
11/14/12 (6)		0.5325		14,607		N/A		122		290		15,019
2013
02/14/13 (7)	$	0.5700	$	15,636		N/A	$	131	$	579	$	16,346
05/15/13 (8)		0.5825		15,979		N/A		134		683		16,796
08/14/13 (9)		0.5875		16,116		N/A		135		724		16,975
11/14/13 (10)		0.6000		16,459		N/A		138		828		17,425

(1): On February 16, 2011, based upon satisfying certain distribution and performance tests provided in the Partnership's partnership agreement, all 5,642,424 subordinated units converted to common units. Prior to the conversion, the Partnership made this distribution in the following manner: firstly, 98.80% to the common unitholders, pro rata, and 1.20% to the General Partner, until the Partnership distributed for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter; secondly, 98.80% to the common unitholders, pro rata, and 1.20% to the General Partner, until the Partnership distributed for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period; thirdly, 98.80% to the subordinated unitholders, pro rata, and 1.20% to the General Partner, until the Partnership distributed for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter.
(2): This distribution of $0.50 per unit resulted in the Partnership exceeding its first target level distribution for the fourth quarter of 2010, the four quarters of 2011 and the first quarter of 2012. As a result, the General Partner, as the holder of the IDRs, received an incentive distribution.
(3): Prior to the Partnership's issuance of 5,850,000 common units in connection with its acquisition of Alliance, the limited partner interest was 98.94% and the general partner interest was 1.06%.
(4): In connection with the acquisition of Alliance on March 1, 2012 and the issuance to the seller of 5,850,000 common units, the Contribution Agreement provided that any declared distribution for the first quarter of 2012 reflect the seller's actual period of ownership during that quarter. The payment by the seller of $1.9 million reflects the timing of the transaction (March 1), the seller's 31 days of actual unit ownership in the 91 days of the quarter and the net receipt by seller ($1.0 million) of a pro-rated portion of the quarterly cash distribution of $0.50 per unit paid on the issued 5,850,000 common units.
(5): This distribution of $0.5250 per unit resulted in the Partnership exceeding its first target level distribution for the second quarter of 2012. As a result, the General Partner, as the holder of the IDRs, received an incentive distribution.
(6): This distribution of $0.5325 per unit resulted in the Partnership exceeding its first target level distribution for the third quarter of 2012. As a result, the General Partner, as the holder of the IDRs, received an incentive distribution.

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Note 14. Partners' Equity, Allocations and Cash Distributions (continued)

(7): This distribution of $0.57 per unit resulted in the Partnership exceeding its second target level distribution for the fourth quarter of 2012. As a result, the General Partner, as the holder of the IDRs, received an incentive distribution.
(8): This distribution of $0.5825 per unit resulted in the Partnership exceeding its second target level distribution for the first quarter of 2013. As a result, the General Partner, as the holder of the IDRs, received an incentive distribution.
(9): This distribution of $0.5875 per unit resulted in the Partnership exceeding its second target level distribution for the second quarter of 2013. As a result, the General Partner, as the holder of the IDRs, received an incentive distribution.
(10): This distribution of $0.60 per unit resulted in the Partnership exceeding its second target level distribution for the third quarter of 2013. As a result, the General Partner, as the holder of the IDRs, received an incentive distribution.

In addition, on January 22, 2014, the board of directors of the General Partner declared a quarterly cash distribution of $0.6125 per unit for the period from October 1, 2013 through December 31, 2013 ($2.45 per unit on an annualized basis) to the Partnership's common unitholders of record as of the close of business February 14, 2014. On February 5, 2014, the Partnership paid the total cash distribution of approximately $17.9 million.

Note 15. Unitholders' Equity

On March 1, 2012 and in connection with the acquisition of Alliance (see Note 3), the Partnership issued 5,850,000 common units representing limited partner interests in the Partnership which had a fair value of $22.31 per unit on March 1, 2012, resulting in equity consideration of $130.5 million.

On February 8, 2011, the Partnership completed a public offering of 2,645,000 common units at a price of $27.60 per common unit. Net proceeds were approximately $69.6 million for the year ended December 31, 2011, after deducting underwriting fees and offering expenses. The Partnership used the net proceeds to reduce indebtedness outstanding under its Credit Agreement.

Note 16. Related-Party Transactions

The Partnership is a party to a Second Amended and Restated Terminal Storage Rental and Throughput Agreement, as amended, with Global Petroleum Corp. ("GPC"), an affiliate of the Partnership that is 100% owned by members of the Slifka family. The agreement, which extends through July 31, 2015, is accounted for as an operating lease. After July 31, 2015, the agreement continues for successive one year terms unless either party gives notice to terminate at least 90 days prior to the expiration of the then current term.

The following provides future minimum payments at December 31, 2013, including the expected exercise of renewal options, which have an annual consumer price index adjustment (in thousands):


2014	$	7,262
2015 (1/1/15 - 7/31/15)		4,236


Total	$	11,498

The expenses under this agreement totaled $9.1 million, $8.9 million and $8.8 million for the years ended December 31, 2013, 2012 and 2011, respectively. These expenses include annual consumer price index adjustments of approximately $1.8 million, $1.7 million and $1.5 million for the years ended December 31, 2013, 2012 and 2011, respectively.

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Note 16. Related-Party Transactions (continued)

Pursuant to an Amended and Restated Services Agreement with GPC, GPC provides certain terminal operating management services to the Partnership and uses certain administrative, accounting and information processing services of the Partnership. The expenses from these services totaled approximately $96,000 for each of the years ended December 31, 2013, 2012 and 2011. These charges were recorded in selling, general and administrative expenses in the accompanying consolidated statements of income. On March 9, 2012, in connection with the Partnership's acquisition of Alliance (see Note 3), the agreement was amended to include the services provided by GPC to Alliance. The agreement is for an indefinite term, and either party may terminate its receipt of some or all of the services thereunder upon 180 days' notice at any time. As of December 31, 2013, no such notice of termination was given by either party.

Prior to the acquisition of Alliance on March 1, 2012, the Partnership was a party to an Amended and Restated Services Agreement with Alliance. Pursuant to the agreement, the Partnership provided certain administrative, accounting and information processing services, and the use of certain facilities, to Alliance. The income from these services was approximately $31,000 and $187,000 for the years ended December 31, 2012 and 2011, respectively. These fees were recorded as an offset to selling, general and administrative expenses in the accompanying consolidated statements of income. On March 9, 2012, in connection with the acquisition of Alliance, the agreement was terminated without penalty. There were no settlement gains or losses recognized as a result of the termination of this agreement.

In addition, on March 9, 2012, following the closing of the acquisition of Alliance, Global Companies and AE Holdings entered into a shared services agreement pursuant to which Global Companies provides AE Holdings with certain tax, accounting, treasury and legal support services for which AE Holdings pays Global Companies $15,000 per year. The shared services agreement is for an indefinite term and AE Holdings may terminate its receipt of some or all of the services upon 180 days' notice. As of December 31, 2013, no such notice of termination was given by AE Holdings.

Prior to the acquisition of Alliance on March 1, 2012, the Partnership sold refined petroleum products and renewable fuels to Alliance at prevailing market prices at the time of delivery. Sales to Alliance were approximately $40.6 million and $187.1 million for the years ended December 31, 2012 and 2011, respectively. Sales to Alliance included sales of Mobil-branded fuel to Alliance pursuant to the Mobil franchise agreement entered into by Global Companies and Alliance, effective March 1, 2011.

In addition, Global Companies and GMG entered into management agreements with Alliance in connection with the Partnership's September 2010 acquisition of retail gasoline stations from ExxonMobil. The management fee and overhead reimbursement were approximately $0.4 million and $0.3 million, respectively, for the year ended December 31, 2012 and $2.6 million and $1.6 million, respectively, for the year ended December 31, 2011. On March 9, 2012, in connection with the acquisition of Alliance, the management agreements were terminated without penalty.

The General Partner employs all of the Partnership's employees, except for its gasoline station and convenience store employees and certain union personnel, who are employed by GMG. The Partnership reimburses the General Partner for expenses incurred in connection with these employees. These expenses, including payroll, payroll taxes and bonus accruals, were $63.3 million, $44.9 million and $48.9 million for the years ended December 31, 2013, 2012 and 2011, respectively. The Partnership

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Note 16. Related-Party Transactions (continued)

also reimburses the General Partner for its contributions under the General Partner's 401(k) Savings and Profit Sharing Plan (see Note 11) and the General Partner's qualified and non-qualified pension plans.

The table below presents trade receivables with GPC and the Partnership and receivables from the General Partner at December 31 (in thousands):

	2013		2012

Receivables from GPC	$	436	$	275
Receivables from the General Partner (1)		968		1,032


Total	$	1,404	$	1,307

(1): Receivables from the General Partner reflect the Partnership's prepayment of payroll taxes and payroll accruals to the General Partner.

Note 17. Segment Reporting

The Partnership engages in the distribution of refined petroleum products, renewable fuels, crude oil, natural gas and propane. The Partnership also engages in the purchasing, selling and logistics of transporting domestic and Canadian crude oil and other products. The Partnership's operating segments are based upon the revenue sources for which discrete financial information is reviewed by the chief operating decision maker (the "CODM") and include Wholesale, Gasoline Distribution and Station Operations and Commercial. Each of these operating segments generates revenues and incurs expenses and is evaluated for operating performance on a regular basis.

These operating segments are also the Partnership's reporting segments based on the way the CODM manages the business and on the similarity of customers and expected long-term financial performance of each segment. 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 as defined in accounting guidance related to segment reporting. However, the Partnership has elected to present segment disclosures for the Commercial operating segment as management believes such disclosures are meaningful to the user of the Partnership's financial information. The accounting policies of the segments are the same as those described in Note 2, "Summary of Significant Accounting Policies.".

In the Wholesale reporting segment, the Partnership sells unbranded gasoline (including gasoline blendstocks such as ethanol and naphtha) and diesel to unbranded gasoline customers and other resellers of transportation fuels. The Partnership sells home heating oil, diesel, kerosene, residual oil and propane to home heating oil retailers and wholesale distributors. The Partnership also sells and transports crude oil to refiners. 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 the Partnership owns or controls or with which it has throughput or exchange arrangements. 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

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Note 17. Segment Reporting (continued)

and by barge. The results of Basin Transload and Cascade Kelly, both acquired in February 2013 (see Note 3), are included in the Wholesale segment.

In the Gasoline Distribution and Station Operations reporting segment, the Partnership sells 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 the Partnership's directly operated stores, as well as rental income from dealer leased or commission agent leased gasoline stations.

The 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, the Partnership sells products primarily either through a competitive bidding process or through contracts of various terms. The Commercial segment also includes sales of custom blended fuels delivered by barges or from a terminal dock to ships through bunkering activity.

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, the Partnership generally arranges the delivery of the product to the customer's designated location. The Partnership typically hires third-party common carriers to deliver the product.

The Partnership evaluates segment performance based on product margins before allocations of corporate and indirect operating costs, depreciation, amortization (including non-cash charges) and interest. Based on the way the CODM manages the business, it is not reasonably possible for the Partnership to allocate the components of operating costs and expenses among the reportable segments. There were no intersegment sales for any of the periods presented below.

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Note 17. Segment Reporting (continued)

Summarized financial information for the Partnership's reportable segments for the years ended December 31 is presented in the table below (in thousands):

	Year Ended December 31,

	2013			2012			2011
Wholesale Segment (1):
Sales
Gasoline and gasoline blendstocks	$	8,085,225		$	8,827,621		$	8,660,412
Crude oil (2)		3,561,428			1,205,588			40,873
Other oils and related products (3)		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 (2)		92,807			35,538			12,301
Other oils and related products (3)		66,916			55,252			55,308


Total	$	202,870		$	145,429		$	123,833
Gasoline Distribution and Station Operations Segment (4):
Sales
Gasoline	$	3,231,925		$	3,024,775		$	1,404,988
Station operations (5)		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 (5)		80,106			66,384			31,491


Total	$	230,253		$	206,090		$	88,181
Commercial Segment:
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 (6)	$	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

(1): Segment reporting results for the prior periods have been reclassified to conform to the Partnership's current presentation.
(2): Crude oil consists of the Partnership's crude oil sales and revenue from its logistics activities and includes the February 2013 acquisitions of Basin Transload and Cascade Kelly (see Note 3). 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.
(3): Other oils and related products primarily consist of distillates, residual oil and propane.
(4): On March 1, 2012, the Partnership completed its 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.
(5): Station operations primarily consist of convenience store sales at the Partnership's directly operated stores and rental income from dealer leased or commission agent leased gasoline stations.
(6): Product margin is a non-GAAP financial measure used by management and external users of the Partnership's consolidated financial statements to assess the Partnership's business. The table above includes a reconciliation of product margin on a combined basis to gross profit, a directly comparable GAAP measure.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 17. Segment Reporting (continued)

In the Wholesale segment, the Partnership had two significant customers, ExxonMobil and Phillips 66 whose revenues were approximately $2.9 billion (15%) and $2.4 billion (12%), respectively, of the Partnership's total revenues for the year ended December 31, 2013. The Partnership had one customer, ExxonMobil, whose revenues were approximately $2.8 billion (16%) and $2.8 billion (19%) of the Partnership's total revenues for the years ended December 31, 2012 and 2011, respectively.

A reconciliation of the totals reported for the reportable segments to the applicable line items in the consolidated financial statements is as follows (in thousands):

	Year Ended December 31,

	2013			2012			2011
Combined gross profit	$	405,829		$	333,488		$	209,598
Operating costs and expenses not allocated to operating segments:
Selling, general and administrative expenses		115,491			95,710			73,882
Operating expenses		185,713			140,413			73,534
Restructuring charges		—			—			2,030
Amortization expense		19,216			7,024			4,800


Total operating costs and expenses		320,420			243,147			154,246


Operating income		85,409			90,341			55,352
Interest expense		(43,537	)		(42,021	)		(35,932	)
Income tax expense		(819	)		(1,577	)		(68	)


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

In 2013, the Partnership's foreign sales were immaterial. There were no foreign sales for the years ended December 31, 2012 and 2011. The Partnership has no foreign assets.

Segment Assets

In connection with its acquisitions of Cascade Kelly and a 60% membership interest in Basin Transload in February 2013, the Partnership acquired assets, including goodwill, of approximately $240.5 million, of which approximately $90.0 million of property and equipment has primarily been allocated to the Wholesale segment as of the respective acquisition dates. As of December 31, 2013, the total property and equipment related to these assets had a net book value of approximately $83.2 million.

The Partnership acquired retail gasoline stations from Alliance in March 2012 and ExxonMobil in September 2010 which have been allocated to the Gasoline Distribution and Station Operations segment. As of December 31, 2013, total property and equipment allocated to this segment had a net book value of approximately $500.0 million.

Due to the commingled nature and uses of the remainder of the Partnership's assets, it is not reasonably possible for the Partnership to allocate these assets among its reportable segments.

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Note 18. Fair Value Measurements

Certain of the Partnership's assets and liabilities are measured at fair value. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants at the measurement date. The FASB established a fair value hierarchy, which prioritizes the inputs used in measuring fair value into the following three levels:

Level 1 —Observable inputs such as quoted prices in active markets for identical assets or liabilities.

Level 2 —Inputs other than the quoted prices in active markets that are observable for assets or liabilities, either directly or indirectly. These include quoted prices for similar assets or liabilities in active markets and quoted prices for identical or similar assets or liabilities in inactive markets.

Level 3 —Unobservable inputs based on the entity's own assumptions.

The following table presents those financial assets and financial liabilities measured at fair value on a recurring basis (in thousands):

	Fair Value as of December 31, 2013												Fair Value as of December 31, 2012

	Total			Level 1			Level 2			Level 3			Total			Level 1			Level 2			Level 3
Assets:
Hedged inventories	$	452,302		$	—		$	452,302		$	—		$	526,107		$	—		$	526,107		$	—
Fair value of forward fixed price contracts		46,007			—			31,931			14,076			48,062			—			48,062			—
Swap agreements and options		116			74			42			—			179			54			125			—
Foreign currency derivatives		—			—			—			—			145			—			145			—
Interest rate cap		26			—			26			—			35			—			35			—
Broker margin deposits		21,792			21,792			—			—			54,726			54,726			—			—
Pension plan		18,267			18,267			—			—			17,158			17,158			—			—


Total	$	538,510		$	40,133		$	484,301		$	14,076		$	646,412		$	71,938		$	574,474		$	—




Liabilities:
Obligations on forward fixed price contracts	$	(38,197	)	$	—		$	(33,014	)	$	(5,183	)	$	(34,474	)	$	—		$	(34,474	)	$	—
Mark to market loss related to RIN forward commitments		(6,166	)		—			(6,166	)		—			—			—			—			—
Swap agreements and option contracts		(108	)		(74	)		(34	)		—			(54	)		(54	)		—			—
Foreign currency derivatives		(16	)		—			(16	)		—			—			—			—			—
Interest rate collar and swap		(9,462	)		—			(9,462	)		—			(13,402	)		—			(13,402	)		—


Total liabilities	$	(53,949	)	$	(74	)	$	(48,692	)	$	(5,183	)	$	(47,930	)	$	(54	)	$	(47,876	)	$	—

This table excludes cash on hand and assets and liabilities that are measured at historical cost or any basis other than fair value. The carrying amounts of certain of the Partnership's financial instruments, including cash equivalents, accounts receivable, accounts payable and other accrued liabilities approximate fair value due to their short maturities. The carrying value of the Partnership's credit facilities approximate fair value due to the variable rate nature of these financial instruments.

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Note 18. Fair Value Measurements (continued)

The difference in the fair value and the carrying value of the senior notes issued in 2013 is not material at December 31, 2013 based on the nature of debt and timing of issuance. The fair values of the derivatives used by the Partnership are disclosed in Note 4.

The majority of the Partnership's derivatives outstanding are reported at fair value based market quotes that are deemed to be observable inputs in an active market for similar assets and liabilities and are considered Level 2 inputs for purposes of fair value disclosures. Specifically, the fair values of the Partnership's financial assets and financial liabilities provided above were derived from NYMEX and New York Harbor quotes for the Partnership's hedged inventories, forward fixed price contracts, swap agreements and option contracts and from the LIBOR rates for the Partnership's interest rate collar, interest rate swap and interest rate cap. The fair value of the foreign currency derivatives and the loss related to RIN forward commitments are based on broker price quotations. Except as discussed below, the Partnership has not changed its valuation techniques or inputs during the years ended December 31, 2013 and 2012.

The fair value for the Partnership's forward fixed price contracts related to crude oil are derived from a combination of quoted NYMEX market commodity prices as well as significant unobservable inputs (Level 3), including internally developed assumptions where there is little, if any, market activity. The unobservable inputs used in the measurement of the Partnership's forward fixed price contracts include estimates for location basis, transportation and throughput costs net of an estimated margin for current market participants. Gains and losses recognized in earnings (or changes in net assets) are disclosed in Note 4.

The following table presents a summary of the changes in fair value of the Partnership's Level 3 financial assets and liabilities at December 31, 2013 (in thousands):

	Assets

Fair value at December 31, 2012	$	—
Reclass of Level 2 inputs		15,127
Change in fair value recorded in cost of sales		(6,233	)


Fair value at December 31, 2013	$	8,894

The fair values of the Partnership's pension plan assets at December 31, 2013 and 2012 were determined by Level 1 inputs which principally consist of quoted prices in active markets for identical assets. The plan assets primarily consisted of fixed income securities, equity securities and cash and cash equivalents.

For assets and liabilities measured on a non-recurring basis during the year, accounting guidance requires quantitative disclosures about the fair value measurements separately for each major category. See Note 3 for acquired assets and liabilities measured on a non-recurring basis during the fiscal year ended December 31, 2013.

Financial Instruments

The fair value of the Partnership's financial instruments approximated the carrying value as of December 31, 2013 and 2012, in each case due to the short-term nature and the variable interest rate of the financial instruments.

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Note 19. Changes in Accumulated Other Comprehensive Income

The following table presents the changes in accumulated other comprehensive loss by component (in thousands):

	Pension Plan			Derivatives			Total

Balance at December 31, 2011	$	(3,118	)	$	(17,377	)	$	(20,495	)
Other comprehensive income before reclassifications of gain (loss)		(1,666	)		2,591			825
Amount of gain (loss) reclassified from accumulated other comprehensive income		(100	)		—			—


Total comprehensive income		(1,766	)		2,591			825
Balance at December 31, 2012		(4,884	)		(14,786	)		(19,670	)
Other comprehensive income before reclassifications of gain (loss)		4,540			3,930			8,360
Amount of gain (loss) reclassified from accumulated other comprehensive income		(110	)		—			—


Total comprehensive income		4,430			3,930			8,360


Balance at December 31, 2013	$	(454	)	$	(10,856	)	$	(11,310	)

Note 20. Legal Proceedings

General

Although the Partnership may, from time to time, be involved in litigation and claims arising out of its operations in the normal course of business, the Partnership does not believe that it is a party to any litigation that will have a material adverse impact on its financial condition or results of operations. Except as described below and in Note 9 included herein, the Partnership is not aware of any significant legal or governmental proceedings against it, or contemplated to be brought against it. The Partnership maintains insurance policies with insurers in amounts and with coverage and deductibles as its general partner believes are reasonable and prudent. However, the Partnership can provide no assurance that this insurance will be adequate to protect it 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.

Other

On December 30, 2013, the Oregon Department of Environmental Quality ("ODEQ") unilaterally modified (the "Modification") an air emissions permit held by the Partnership's subsidiary, Cascade Kelly Holdings LLC, which covers both the production of ethanol and transshipping of crude oil by the Partnership's 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 the Partnership's transloading operations. The Partnership submitted a request for a hearing contesting the Modification, which allows the Existing Permit to remain in effect pending such appeal. In addition, the Partnership received a Pre-Enforcement Notice ("PEN") letter dated January 10, 2014 from ODEQ claiming that the Partnership is in violation of the Existing Permit and informing it that ODEQ is considering a possible notice of violation and penalty assessment. In summary, the PEN asserts that the Partnership may have received, and be receiving, more crude oil than the Existing Permit allows. On March 27, 2014, ODEQ issued the Partnership a civil penalty assessment ("CPA") of $117,292. The

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 20. Legal Proceedings (continued)

Partnership believes that it has 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, the Partnership submitted an application to ODEQ for a separate air emissions permit covering the transloading of crude oil by the bio-refinery (the "New Permit"). The Partnership is working through the customary permitting process with ODEQ. The draft of the New Permit is currently out for public notice and comment. The Partnership anticipates that the New Permit will be issued in the second quarter of 2014. The Partnership believes 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 the Partnership's operations in Oregon.

The Partnership received from the Environmental Protection Agency (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 the Partnership has violated sections of the Clean Air Act at certain of its terminal locations in New England with respect to residual oil and asphalt. The Partnership has submitted all required information requested under the Requests for Information. The Partnership does not believe that a material violation has occurred nor does the Partnership believe any adverse determination in connection with such investigation would have a material impact on its operations.

Note 21. Supplemental Information and Non-Cash Investing Activities

The following presents cash flow supplemental information for the years ended December 31 (in thousands):

	2013		2012		2011

Cash paid during the year for interest	$	34,179	$	36,356	$	31,496
Cash paid during the year for income taxes	$	273	$	919	$	6
Non-cash conversion of subordinated unitholders	$	—	$	—	$	1,623

The following presents non-cash investing activities for the year ended December 31, 2012 (in thousands):


Effect of acquisition of Alliance Energy LLC:
Fair value of tangible assets acquired	$	(332,779	)
Fair value of liabilities assumed		82,935
Fair value of acquired intangible assets		(31,135	)
Consideration paid in excess of fair value (goodwill)		(31,432	)
Fair value of common units issued		130,513


Net cash paid in connection with the acquisition of Alliance		(181,898	)
Effect of acquisition of Mutual Oil Company.:
Fair value of tangible assets acquired		(6,302	)
Fair value of liabilities assumed		627
Consideration paid in excess of fair value (goodwill)		(1,175	)


Net cash paid in connection with the acquisition of Mutual Oil		(6,850	)


Total net cash paid in connection with acquisitions	$	(188,748	)




Non-cash purchase of underground storage tanks	$	3,750

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 22. Quarterly Financial Data (Unaudited)

Unaudited quarterly financial data is as follows (in thousands, except per unit amounts):

	First			Second		Third		Fourth		Total

Year ended December 31, 2013
Sales	$	5,589,190		$	4,771,756	$	4,433,426	$	4,795,236	$	19,589,608
Gross profit (1)(2)	$	59,072		$	93,797	$	118,093	$	134,867	$	405,829
Net (loss) income (1)(2)(3)	$	(22,316	)	$	5,204	$	25,136	$	33,029	$	41,053
Net (loss) income attributable to Global Partners LP	$	(22,067	)	$	4,825	$	25,815	$	34,042	$	42,615
Limited partners' interest in net (loss) income	$	(22,567	)	$	4,061	$	24,773	$	32,827	$	39,094
Basic net (loss) income per limited partner unit (4)	$	(0.83	)	$	0.15	$	0.91	$	1.20	$	1.43
Diluted net (loss) income per limited partner unit (4)	$	(0.83	)	$	0.15	$	0.91	$	1.20	$	1.42
Cash distributions per limited partner unit (5)	$	0.57		$	0.5825	$	0.5875	$	0.60	$	2.34

	First			Second		Third		Fourth		Total

Year ended December 31, 2012
Sales	$	3,975,481		$	3,916,063	$	4,617,194	$	5,117,259	$	17,625,997
Gross profit	$	55,319		$	90,675	$	82,620	$	104,874	$	333,488
Net (loss) income	$	(1,400	)	$	18,515	$	6,893	$	22,735	$	46,743
Limited partners' interest in net (loss) income	$	(1,508	)	$	18,206	$	6,577	$	22,256	$	45,531
Basic net (loss) income per limited partner unit (4)	$	(0.06	)	$	0.67	$	0.24	$	0.81	$	1.73
Diluted net (loss) income per limited partner unit (4)	$	(0.06	)	$	0.66	$	0.24	$	0.81	$	1.71
Cash distributions per limited partner unit (5)	$	0.50		$	0.50	$	0.5250	$	0.5325	$	2.06

(1): Includes $32.7 million of expense, $10.6 million of income, $15.5 million of income and $0.4 million of income for the quarters ended March 31, June 30, September 30 and December 31, 2013, respectively, related to the change in the liability for losses on RIN forward commitments.
(2): Includes $2.6 million of expense, $6.5 million of expense, $13.5 million of expense and $9.5 million of income for the quarters ended March 31, June 30, September 30 and December 31, 2013, respectively, related to changes in the RVO Deficiency.
(3): Includes a $2.5 million non-recurring charge for the quarter ended December 31, 2013 related to the write off of a prepaid consulting agreement that is no longer realizable.
(4): See Note 2 for net income per limited partner unit calculation.
(5): Cash distributions declared in one calendar quarter are paid in the following calendar quarter.

As previously disclosed in the amended Form 10-Q/As for the interim periods ended March 31, June 30 and September 30, 2013, the Partnership has restated its interim 2013 financial results, principally related to the accounting for RINS and certain accrued liabilities related to the procurement of petroleum products. The quarterly results above reflect these corrections. For the three months ended March 31, 2013, these corrections reduced net income attributable to Global Partners LP by $36.9 million and basic net income per limited partner unit by $1.34 per unit. For the three months ended June 30, 2013, these corrections reduced net income attributable to Global Partners LP by $3.9 million and basic net income per limited partner unit by $0.14 per unit. For the three months ended September 30, 2013, these corrections increased net income attributable to Global Partners LP by $22.4 million and basic net income per limited partner unit by $0.82 per unit. Net income from continuing operations was equivalent to net income attributable to Global Partners LP for all restated periods.

Note 23. Subsequent Event

On February 14, 2014, the Partnership paid a cash distribution of approximately $17.9 million to its common unitholders of record as of the close of business on February 5, 2014.

F-64

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Item 15(a)

SCHEDULE II—VALUATION AND QUALIFYING ACCOUNTS
GLOBAL PARTNERS LP
FOR THE YEARS ENDED DECEMBER 31, 2013, 2012 and 2011
(In thousands)

Description	Balance at Beginning of Period		Charged to Costs and Expenses		Recoveries		Write Offs			Balance at End of Period

*Year ended December 31, 2013*
Allowance for doubtful accounts—accounts receivable	$	4,732	$	4,145	$	9	$	(1,772	)	$	7,114
*Year ended December 31, 2012*
Allowance for doubtful accounts—accounts receivable	$	4,375	$	869	$	—	$	(512	)	$	4,732
*Year ended December 31, 2011*
Allowance for doubtful accounts—accounts receivable	$	3,799	$	1,860	$	—	$	(1,284	)	$	4,375

F-65

Table of Contents

INDEX TO EXHIBITS

			Description

2.1	**	—	Contribution Agreement dated November 21, 2011, by and among Global Partners LP and AE Holdings Corp. (incorporated herein by reference to Exhibit 2.1 to the Current Report on Form 8-K filed on November 23, 2011).
2.2		—	Exhibit A to Contribution Agreement (Exhibit 2.1), Determination of the Cash Adjustment (incorporated herein by reference to Exhibit 2.2 to the Current Report on Form 8-K filed on November 23, 2011).
2.3	**	—	Membership Interest Purchase Agreement, dated as of January 22, 2013, between JH Kelly Holdings LLC and Global Partners LP (incorporated herein by reference to Exhibit 2.1 to the Current Report on Form 8-K filed on February 22, 2013).
3.1		—	Third Amended and Restated Agreement of Limited Partnership of Global Partners LP dated as of December 9, 2009 (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K filed on December 15, 2009).
4.1		—	Registration Rights Agreement, dated May 9, 2007, by and between Global Partners LP and the purchasers named therein (incorporated herein by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on May 10, 2007).
4.2		—	Registration Rights Agreement, dated March 1, 2012, by and among Global Partners LP and AE Holdings Corp. (incorporated herein by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on March 7, 2012).
4.3		—	Indenture, dated as of February 14, 2013, by and among Global Partners LP and GLP Finance Corp., as Issuers, the Guarantors party thereto and FS Energy and Power Fund, as Purchaser (incorporated herein by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on February 21, 2013).
4.4		—	Indenture, dated as of December 23, 2013, by and among Global Partners LP and GLP Finance Corp., as Issuers, the Guarantors party thereto and 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 (incorporated herein by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on December 26, 2013).
4.5		—	Second Supplemental Indenture, dated as of December 20, 2013, by and among Global Partners LP, GLP Finance Corp., as Issuers, the Guarantors party thereto and FS Energy and Power Fund, as Purchaser (incorporated herein by reference to Exhibit 4.2 to the Current Report on Form 8-K filed on December 26, 2013).
10.1		—	Omnibus Agreement, dated October 4, 2005, by and among Global Petroleum Corp., Montello Oil Corporation, Global Revco Dock, L.L.C., Global Revco Terminal, L.L.C., Global South Terminal, L.L.C., Sandwich Terminal, L.L.C., Chelsea Terminal Limited Partnership, Global GP LLC, Global Partners LP, Global Operating LLC, Alfred A. Slifka, Richard Slifka and Eric Slifka (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on October 11, 2005).
10.2		—	Amended and Restated Services Agreement, dated October 4, 2005, by and among Global Petroleum Corp., Global Companies LLC, Global Montello Group LLC, and Chelsea Sandwich LLC (incorporated herein by reference to Exhibit 10.3 to the Current Report on Form 8-K filed on October 11, 2005).
10.3		—	Second Amended and Restated Terminal Storage and Throughput Agreement, dated October 4, 2005 by and among Global Petroleum Corp., Global Companies LLC and Global Montello Group LLC (incorporated herein by reference to Exhibit 10.5 to the Current Report on Form 8-K filed on October 11, 2005).
10.4	^	—	Employment Agreement dated April 19, 2006, by and between Global GP LLC and Thomas J. Hollister (incorporated herein by reference to Exhibit 99.1 to the Current Report on Form 8-K filed on May 11, 2006).

Table of Contents

			Description

10.5	^	—	Employment Agreement dated February 1, 2007, by and between Global GP LLC and Edward J. Faneuil (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on February 6, 2007).
10.6		—	Terminals Sale and Purchase Agreement, dated March 16, 2007 by and between Global Partners LP and ExxonMobil Oil Corporation (incorporated herein by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q filed on August 9, 2007).
10.7	^	—	Forms of LTIP Grant Agreements dated August 14, 2007 (Named Executive Officers who are party to an employment agreement with Global GP LLC) (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on August 20, 2007).
10.8	^	—	Form of LTIP Grant Agreement (Directors) (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on August 20, 2007).
10.9	^	—	Form of LTIP Grant Agreement (General) (incorporated herein by reference to Exhibit 10.3 to the Current Report on Form 8-K filed on August 20, 2007).
10.10		—	Terminals Sale and Purchase Agreement, dated July 9, 2007 by and between Global Partners LP and ExxonMobil Oil Corporation (incorporated herein by reference to Exhibit 10.21 to the Annual Report on Form 10-K filed on March 14, 2008).
10.11	^	—	Employment Agreement dated December 31, 2008, by and between Global GP LLC and Eric S. Slifka (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on January 7, 2009).
10.12	^	—	Amendment No. 1 to Employment Agreement dated December 31, 2008, by and between Global GP LLC and Thomas Hollister (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on January 7, 2009).
10.13	^	—	Amendment No. 1 to Employment Agreement dated December 31, 2008, by and between Global GP LLC and Edward J. Faneuil (incorporated herein by reference to Exhibit 10.3 to the Current Report on Form 8-K filed on January 7, 2009).
10.14	^	—	Amended and Restated Deferred Compensation Agreement dated December 31, 2008, by and between Global GP LLC and Edward J. Faneuil (incorporated herein by reference to Exhibit 10.4 to the Current Report on Form 8-K filed on January 7, 2009).
10.15	^	—	First Amendment to LTIP Grant Agreement dated December 31, 2008 for Eric Slifka (incorporated herein by reference to Exhibit 10.5 to the Current Report on Form 8-K filed on January 7, 2009).
10.16	^	—	First Amendment to LTIP Grant Agreement (Named Executive Officers who are party to an employment agreement with Global GP LLC (except Mr. Slifka)), LTIP Grant Agreement (Directors) and LTIP Grant Agreement (General) dated December 31, 2008 (incorporated herein by reference to Exhibit 10.6 to the Current Report on Form 8-K filed on January 7, 2009).
10.17	^	—	Amendment No. 1 to Employment Agreement dated February 4, 2009, by and between Global GP LLC and Eric S. Slifka (incorporated herein by reference to Exhibit 10.30 to the Annual Report on Form 10-K filed on March 13, 2009).
10.18	^	—	Amendment No. 2 to Employment Agreement dated February 4, 2009, by and between Global GP LLC and Thomas Hollister (incorporated herein by reference to Exhibit 10.31 to the Annual Report on Form 10-K filed on March 13, 2009).
10.19	^	—	Amendment No. 2 to Employment Agreement dated February 4, 2009, by and between Global GP LLC and Edward J. Faneuil (incorporated herein by reference to Exhibit 10.32 to the Annual Report on Form 10-K filed on March 13, 2009).
10.20	^	—	Amendment No. 3 to Employment Agreement dated March 11, 2009, by and between Global GP LLC and Edward J. Faneuil (incorporated herein by reference to Exhibit 10.33 to the Annual Report on Form 10-K filed on March 13, 2009).

Table of Contents

			Description

10.21	^	—	Supplemental Executive Retirement Plan dated December 31, 2009, between Global GP LLC and Edward J. Faneuil (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on January 7, 2010).
10.22	^	—	Supplemental Executive Retirement Plan dated December 31, 2009, between Global GP LLC and Charles A. Rudinsky (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on January 7, 2010).
10.23		—	First Amendment to Second Amended and Restated Terminal Storage Rental and Throughput Agreement, dated May 12, 2010 among Global Petroleum Corp., Global Companies LLC and Global Montello Group Corp. (incorporated herein by reference to Exhibit 10.3 to the Current Report on Form 8-K filed on May 18, 2010).
10.24		—	Sale and Purchase Agreement, dated May 24, 2010 among ExxonMobil Oil Corporation and Exxon Mobil Corporation, as sellers, and Global Companies LLC (incorporated herein by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q filed on August 6, 2010).
10.25		—	First Amendment to Sale and Purchase Agreement, effective August 12, 2010 among ExxonMobil Oil Corporation and Exxon Mobil Corporation, as sellers, and Global Companies LLC (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on August 31, 2010).
10.26		—	Second Amendment to Sale and Purchase Agreement, dated September 7, 2010, among ExxonMobil Oil Corporation and Exxon Mobil Corporation, as sellers, and Global Companies LLC, as buyer (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on September 9, 2010).
10.27	^	—	Amendment No. 4 to Employment Agreement dated November 2, 2010 by and between Global GP LLC and Edward J. Faneuil (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on November 8, 2010).
10.28	††	—	Brand Fee Agreement, dated September 3, 2010, between ExxonMobil Oil Corporation and Global Companies LLC (incorporated herein by reference to Exhibit 10.6 to the Quarterly Report on Form 10-Q/A filed on January 20, 2011).
10.29		—	Assignment of Branded Wholesaler PMPA Franchise Agreements, effective March 1, 2011 between Global Companies LLC, Alliance Energy LLC and ExxonMobil Oil Corporation (incorporated herein by reference to Exhibit 10.49 to the Annual Report on Form 10-K filed on March 11, 2011).
10.30	^	—	Employment Agreement dated as of January 1, 2012, by and between Global GP LLC and Eric S. Slifka (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on January 6, 2012).
10.31	^	—	Amendment No. 5 to Employment Agreement dated December 31, 2011, by and between Global GP LLC and Edward J. Faneuil (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on January 6, 2012).
10.32		—	Business Opportunity Agreement, dated March 1, 2012, by and among Alfred A. Slifka, Richard Slifka and Global Partners LP (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on March 7, 2012).
10.33	^	—	Employment Agreement dated March 1, 2012, by and between Global GP LLC and Andrew P. Slifka (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on March 7, 2012).
10.34	^*	—	Deferred Compensation Agreement dated September 23, 2009, by and between Alliance Energy LLC and Edward J. Faneuil (incorporated herein by reference to Exhibit 10.53 to the Annual Report on Form 10-K filed on March 12, 2012).

Table of Contents

			Description

10.35		—	First Amendment to Amended and Restated Services Agreement, dated as of July 24, 2006, by and among Global Petroleum Corp., Global Companies LLC, Global Montello Group Corp. and Chelsea Sandwich LLC (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on March 15, 2012).
10.36		—	Second Amendment to Amended and Restated Services Agreement, dated March 9, 2012, by and among Global Petroleum Corp., Global Companies LLC, Global Montello Group Corp., Chelsea Sandwich LLC and Alliance Energy LLC (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on March 15, 2012).
10.37		—	Services Agreement, dated March 9, 2012, by and between Global Companies LLC and AE Holdings Corp. (incorporated herein by reference to Exhibit 10.3 to the Current Report on Form 8-K filed on March 15, 2012).
10.38	^	—	General Partners LP Long-Term Incentive Plan (As Amended and Restated Effective June 22, 2012) (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on June 25, 2012).
10.39		—	Second Amendment to the Second Amended and Restated Terminal Storage Rental and Throughput Agreement, dated November 14, 2012, among Global Petroleum Corp., Global Companies LLC, Glen Hes and Global Montello Group Corp. (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on November 20, 2012).
10.40		—	Note Purchase Agreement, dated as of February 14, 2013, by and among Global Partners LP and GLP Finance Corp., as Issuers, and FS Energy and Power Fund, as Purchaser (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on February 21, 2013).
10.41	^	—	Retirement, Consulting and Noncompete Agreement, dated April 23, 2013, by and between Global GP LLC and Thomas Hollister (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on April 26, 2013).
10.42	^	—	Form of Phantom Unit Award Agreement for Employees under Global Partners LP Long-Term Incentive Plan (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on July 3, 2013).
10.43	^	—	Form of Phantom Unit Award Agreement for Directors under Global Partners LP Long-Term Incentive Plan (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on July 3, 2013).
10.44	^	—	Executive Change of Control Agreement, effective July 1, 2013, by and between Global GP LLC and Daphne H. Foster (incorporated herein by reference to Exhibit 10.3 to the Current Report on Form 8-K filed on July 3, 2013).
10.45	^	—	Executive Change of Control Agreement, effective July 1, 2013, by and between Global GP LLC and Mark Romaine (incorporated herein by reference to Exhibit 10.4 to the Current Report on Form 8-K filed on July 3, 2013).
10.46	^	—	Executive Change of Control Agreement, effective July 1, 2013, by and between Global GP LLC and Charles A. Rudinsky (incorporated herein by reference to Exhibit 10.5 to the Current Report on Form 8-K filed on July 3, 2013).
10.47	^	—	Form of Confidentiality, Non-Solicitation, and Non-Competition Agreement for Phantom Unit Award Recipients (incorporated herein by reference to Exhibit 10.6 to the Current Report on Form 8-K filed on July 3, 2013).
10.48	^	—	Confidentiality, Non-Solicitation, and Non-Competition Agreement, effective July 1, 2013, by and between Global GP LLC and Daphne H. Foster (incorporated herein by reference to Exhibit 10.7 to the Current Report on Form 8-K filed on July 3, 2013).

Table of Contents

			Description

10.49	^	—	Confidentiality, Non-Solicitation, and Non-Competition Agreement, effective July 1, 2013, by and between Global GP LLC and Mark Romaine (incorporated herein by reference to Exhibit 10.8 to the Current Report on Form 8-K filed on July 3, 2013).
10.50	^	—	Memorandum to Thomas J. Hollister, Follow-up Understandings, dated July 9, 2013 (incorporated herein by reference to Exhibit 10.9 to the Quarterly Report on Form 10-Q filed on November 7, 2013).
10.51		—	Note Purchase Agreement, dated as of December 23, 2013, by and among Global Partners LP and GLP Finance Corp., as Issuers, and 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 (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on December 26, 2013).
10.52	*††		Second Amended and Restated Credit Agreement, dated as of December 16, 2013, among Global Operating LLC, Global Companies LLC, Global Montello Group Corp., Glen Hes Corp., Chelsea Sandwich LLC, GLP Finance Corp., Global Energy Marketing LLC, Global Energy Marketing II LLC, Global CNG LLC, Alliance Energy LLC and Cascade Kelly Holdings LLC as borrowers, Bank of America, N.A., as Administrative Agent, Swing Line Lender, Alternative Currency Fronting Lender and L/C Issuer, JPMorgan Chase Bank, N.A. and Wells Fargo Bank, N.A. as Co-Syndication Agents, RBS Citizens NA, Societe Generale and Standard Chartered Bank as Co-Documentation Agents, and Banc of America Merrill Lynch, JP Morgan Securities Inc. and Wells Fargo Securities, LLC as Joint Lead Arrangers and Joint Book Managers.
21.1	*	—	List of Subsidiaries of Global Partners LP.
23.1	*	—	Consent of Ernst & Young LLP.
31.1	*	—	Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of Global GP LLC, general partner of Global Partners LP.
31.2	*	—	Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of Global GP LLC, general partner of Global Partners LP.
32.1	†	—	Section 1350 Certification of Chief Executive Officer of Global GP LLC, general partner of Global Partners LP.
32.2	†	—	Section 1350 Certification of Chief Financial Officer of Global GP LLC, general partner of Global Partners LP.
101.INS	*	—	XBRL Instance Document.
101.SCH	*	—	XBRL Taxonomy Extension Schema Document.
101.CAL	*	—	XBRL Taxonomy Extension Calculation Linkbase Document.
101.LAB	*	—	XBRL Taxonomy Extension Labels Linkbase Document.
101.PRE	*	—	XBRL Taxonomy Extension Presentation Linkbase Document.
101.DEF	*	—	XBRL Taxonomy Extension Definition Linkbase Document.

^: Management contract or compensatory plan or arrangement.
*: Filed herewith.
†: Not deemed "filed" for purposes of Section 18 of the Securities Exchange Act of 1934 or otherwise subject to the liability of that section.
**: Schedules and similar attachments have been omitted pursuant to Item 601(b)(2) of Regulation S-K. The Partnership undertakes to furnish supplementally copies of any of the omitted schedules and exhibits upon request by the U.S. Securities and Exchange Commission.
††: Portions of this exhibit have been omitted pursuant to a request for confidential treatment. The omitted information has been filed separately with the Securities and Exchange Commission.

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	H.S. junior Avg

GLOBAL PARTNERS LP

Global GP LLC,
its general partner

Dated: March 31, 2014

/s/ ERIC SLIFKA

Eric Slifka
President and Chief Executive Officer