10-K

0.

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10‑K

(Mark One)
☒	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2015
OR
☐	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 ☐ No ☒

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S‑K is not contained herein, and will not be contained, to the best of 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. ☐

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

Large accelerated filer ☒ Accelerated filer ☐ Non‑accelerated filer ☐ Smaller reporting company ☐

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

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 30, 2015 was approximately $834,777,904 based on a price per common unit of $32.44, the price at which the common units were last sold as reported on the New York Stock Exchange on such date.

As of February 25, 2016, 33,995,563 common units were outstanding.

TABLE OF CONTENTS

PART I
Items 1. and 2.	Business and Properties	6
Item 1A.	Risk Factors	21
Item 1B.	Unresolved Staff Comments	48
Item 3.	Legal Proceedings	48
Item 4.	Mine Safety Disclosures	51
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	52
Item 6.	Selected Financial Data	53
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	56
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	84
Item 8.	Financial Statements and Supplementary Data	86
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	87
Item 9A.	Controls and Procedures	87
Item 9B.	Other Information	90
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	91
Item 11.	Executive Compensation	95
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	116
Item 13.	Certain Relationships and Related Transactions, and Director Independence	117
Item 14.	Principal Accounting Fees and Services	121
PART IV
Item 15.	Exhibits and Financial Statement Schedules	122

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Forward‑Looking Statements

Certain statements and information in this Annual Report on Form 10‑K  may constitute “forward‑looking statements.” The words “believe,” “expect,” “anticipate,” “plan,” “intend,” “foresee,” “should,” “would,” “could” or other similar expressions are intended to identify forward‑looking statements, which are generally not historical in nature. These forward‑looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us. While management believes that these forward‑looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate. All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisitions. Our forward‑looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections. Known material factors that could cause our actual results to differ from those in the forward-looking statements are those described in Part I, Item 1A. “Risk Factors.”These risks and uncertainties include, among other things:

· We may not have sufficient cash from operations to enable us to 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 price or demand for the products we sell or a significant decrease in demand for our logistics activities could have an adverse effect on our financial condition, results of operations and cash available for distribution to our unitholders.

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

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

· Erosion of the value of major gasoline brands 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 and logistics activities could be adversely affected by, among other things, unanticipated changes in the crude oil market structure, grade differentials and volatility (or lack thereof), implementation of regulations that adversely impact the market for transporting crude oil or other products by rail, 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.

· We have contractual obligations for certain transportation assets such as railcars, barges and pipelines. A decline in demand for (i) the products we sell, including crude oil and ethanol, or (ii) our logistics activities, could result in a decrease in the utilization of these transportation assets, which could negatively impact our financial condition, results of operations and cash available for distribution to our unitholders. For example, during 2015, we experienced adverse market conditions in crude oil caused by an over-

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supplied crude oil market which resulted in tighter price differentials,  and we experienced a reduction in our railcar movements but remained obligated to pay the applicable fixed charges for railcar leases.Non-utilization of certain of our assets and facilities.

· Changes in government usage mandates and tax credits 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.

· Our risk management policies cannot eliminate all commodity risk, basis risk or the impact of unfavorable market conditions which can adversely affect our financial condition, results of operations and cash available for distribution to our unitholders. 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, and pricing volatility may adversely impact our results.

· 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, logistics disruptions and other factors and uncertainties inherent in the transportation, storage, terminalling and marketing of crude oil and refined products.

· 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 and risk associated with our trade credit support in the ordinary course of our business.

· The condition of credit markets may adversely affect us.

· Our 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 as well as our ability to 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.

· Our business could expose us to 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 have a material adverse effect on such businesses and can 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.

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· We are exposed to performance risk in our supply chain.

· Our business is 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 could permit them to favor their own interests to the detriment of our unitholders.

· Unitholders have limited voting rights and are not entitled to elect our general partner or its directors or remove our general partner without the consent of the holders of at least 66 2/3% 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.

Readers are cautioned not to place undue reliance on forward‑looking statements, which speak only as of the date hereof.  We undertake no obligation to publicly update or revise any forward‑looking statements after the date they are made, whether as a result of new information, future events or otherwise.

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 500, 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 midstream logistics and marketing master limited partnership formed in March 2005 engaged in the purchasing, selling, storing and logistics of transporting petroleum and related products, including domestic and Canadian crude oil, gasoline and gasoline blendstocks (such as ethanol), distillates (such as home heating oil, diesel and kerosene), residual oil, renewable fuels, natural gas and propane. We also receive revenue from convenience store sales and gasoline station rental income. 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 own transload and storage terminals in North Dakota and Oregon that extend our origin‑to‑destination capabilities from the mid‑continent region of the United States and Canada to the East and West Coasts. We are one of the largest distributors of gasoline, distillates, residual oil and renewable fuels to wholesalers, retailers and commercial customers in the New England states and New York. As of December 31, 2015, we had a portfolio of 1,509 owned, leased and/or supplied gasoline stations, including 281 directly operated convenience stores, in the Northeast, Maryland and Virginia.

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. We operate our business under three segments: (i) Wholesale, (ii) Gasoline Distribution and Station Operations (“GDSO”) and (iii) Commercial.

Global GP LLC, our general partner, manages our operations and activities and employs our officers and substantially all of our personnel, except for most of our gasoline station and convenience store employees and certain union personnel who are employed by our wholly owned subsidiary, Global Montello Group Corp. (“GMG”).

Recent Developments and 2015 Transactions

Strategic Steps in the First Quarter of 2016

On January 28, 2016, we announced a reduction in the quarterly distribution for the fourth quarter of 2015 on all outstanding common units to $0.4625.  This distribution represented a decrease of 33.7% from the distribution of $0.6975 per unit paid in November 2015 and a decrease of 30.5% from the distribution of $0.6650 per unit paid in February 2015. The reduction in the distribution primarily reflected continuing weakness in the crude oil market.

During this period of headwinds in the crude oil market, we intend to capitalize on the flexibility of our Oregon facility and take steps to utilize this location for ethanol transloading. This measure is substantially related to cleaning of tanks and associated infrastructure and is expected to be completed in the third quarter of 2016.

As part of expense management initiatives, we reduced our workforce by approximately 70 people, which equates to approximately 8% of our headcount excluding employees at our convenience stores. This reduction included employees at our transloading facilities in Oregon and North Dakota and at our corporate offices.

Acquisitions

Warren Equities, Inc.—On January 7, 2015, we acquired, through GMG, 100% of the equity interests in Warren Equities, Inc. (“Warren”), one of the largest independent marketers of petroleum products in the Northeast, from The Warren Alpert Foundation. The acquisition included 147 company‑owned Xtra Mart convenience stores and related fuel

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operations, 53 commission agent locations and fuel supply rights for approximately 330 dealers. The acquired properties are located in the Northeast, Maryland and Virginia. The purchase price, inclusive of post‑closing adjustments, was approximately $381.8 million, including working capital. This acquisition complements our existing retail presence in the Northeast and expanded our footprint into the adjacent Mid‑Atlantic region. As of the acquisition date, these assets added approximately 500 million gallons of fuel sold annually through our network and increased the number of our total gasoline stations that we own, lease or supply to more than 1,500. The acquisition was funded with borrowings under our credit facility and with proceeds from our public offering of 3,565,000 common units, which closed on December 10, 2014.

Revere Terminal—On January 14, 2015, we acquired the Revere terminal (the “Revere Terminal”) located in Boston Harbor in Revere, Massachusetts from Global Petroleum Corp. (“GPC”) for a purchase price of approximately $23.7 million.GPC is owned by the Estate of Alfred A. Slifka and Richard Slifka. The facility, which had beenleased to us by GPC, has storage capacity of 2.1 million barrels of refined petroleum products, including heating oil, gasoline, distillates, diesel, kerosene and blendstocks. We financed the transaction with available capacity under our revolving credit facility. In connection with the Revere Terminal transaction, the terminal storage rental and throughput agreement between us and GPC terminated effective as of February 1, 2015.

Capitol Petroleum Group—On June 1, 2015, we acquired97 primarily Mobil and Exxon branded owned or leased retail gasoline stations and seven dealer supply contracts in New York City and Prince George’s County, Maryland, along with certain related supply and franchise agreements and third-party leases and other assets associated with the operations from Capitol Petroleum Group (“Capitol”). The purchase price was approximately $155.7 million which was financed with borrowings under our revolving credit facility.

Debt Offering

On June 1, 2015, we closed on an offering of $300.0 million aggregate principal amount of our 7.00% notes due 2023 (the “7.00% Notes”) in a private placement exempt from registration under the Securities Act of 1933, as amended (the “Securities Act”). We used the net proceeds from the offering to repay a portion of the borrowings outstanding under our revolving credit facility. On June 4, 2015, we entered into a registration rights agreement with the initial purchasers of the 7.00% Notes, pursuant to which we agreed to file and use commercially reasonable efforts to cause to become effective a registration statement relating to an offer to exchange the 7.00% Notes for an issue of SEC-registered notes with terms identical to the 7.00% Notes. The exchange offer was completed on October22, 2015, and 100% of the 7.00% Notes have been exchanged for SEC registered notes.Please read Item 7, “Management’s Discussion and Analysis and Results of Operations—Liquidity and Capital Resources” for additional information.

Equity Offering

On June16, 2015, we completed a public offering of 3,000,000 common units at a price to the public of $38.12 per common unit. Net proceeds from the offering were approximately $109.3 million after deducting underwriting discounts and offering expenses. We used the net proceeds from the offering to reduce indebtedness outstanding under our revolving credit facility.

At-the-Market Offering Program

On May 19, 2015, we entered into an equity distribution agreement pursuant to which we may sell from time to time through our sales agents, our common units having an aggregate offering price of up to $50.0 million. Sales of the common units, if any, will be made by any method permitted by law deemed to be an “at-the-market” offering, including ordinary brokers’ transactions through the facilities of the New York Stock Exchange, to or through a market maker or directly on or through an electronic communication network, a “dark pool” or any similar market venue, at market prices, in block transactions, or as otherwise agreed upon by us and one or more of our sales agents.We may also sell common units to one or more of our sales agents as principal for our own account at a price to be agreed upon at the time of sale. Any sale of common units to a sales agent as principal would be pursuant to the terms of a separate agreement between us and such sales agent.

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We intend to use the net proceeds from any sales pursuant to theat‑the‑market offering program, after deducting the sales agents’ commissions and our offering expenses, for general partnership purposes, which may include, among other things, repayment of indebtedness, acquisitions and capital expenditures.As of December 31, 2015, no common units were sold by us pursuant to theat‑the‑market offering program.

Operating Segments

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. We operate our business under three segments: (i) Wholesale, (ii) GDSO and (iii) Commercial. In 2015, our Wholesale, GDSO and Commercial sales accounted for approximately 57%, 36% and 7% of our total sales, respectively.

Wholesale

In our Wholesale segment, we engage in the logistics of selling, gathering, storage and transportation of refined petroleum products, renewable fuels, crude oil and propane. We sell branded and unbranded gasoline and gasoline blendstocks and diesel to wholesale distributors.We transport these products by railcars, barges and/or pipelines pursuant to spot or long‑term contracts.  We aggregate crude oil by truck or pipeline in the mid‑continent region of the United States and Canada, transport it by train and ship it by barge to refiners on the East and West Coasts. We sell home heating oil, diesel, kerosene, residual oil and propane to home heating oil and propane retailers and wholesale distributors. Generally, customers use their own vehicles or contract carriers to take delivery of the gasoline and distillates at bulk terminals and inland storage facilities that we own or control or at which we have throughput or exchange arrangements. Ethanol is shipped primarily by rail and by barge.

Gasoline Distribution and Station Operations

In our GDSO segment, gasoline distribution includes sales of branded and unbranded gasoline to gasoline station operators and sub-jobbers. Station operations include (i)convenience stores,(ii)rental income from gasoline stations leased to dealers, from commissioned agents and from cobranding arrangements and (iii)sundries (such as car wash sales, lottery and ATM commissions). The results of Warren and Capitol are included in the GDSO segment.

As of December 31, 2015, our portfolio of owned, leased and/or supplied gasoline stations, primarily in the Northeast, consisted of the following:

Company operated	281
Commissioned agents	283
Lessee dealers	280
Contract dealers	665
Total	1,509

Commercial

In our Commercial segment, we include 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, bunker fuel and natural gas. In the case of public sector commercial and industrial end user customers, we sell products primarily either through a competitive bidding process or through contracts of various terms. We generally arrange for the delivery of the product to the customer’s designated location, and we respond to publiclyissued requests for product proposals and quotes. Our Commercial segment also includes sales of custom blended fuels delivered by barges or from a terminal dock to ships through bunkering activity.

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Products

General

The following table presents our product sales and other revenues as a percentage of our consolidated sales for the years ended December 31:

	2015		2014		2013
Gasoline sales: gasoline and gasoline blendstocks (such as ethanol)	59	%	60	%	58	%
Crude oil sales and crude oil logistics revenue	12	%	14	%	18	%
Distillates (home heating oil, diesel and kerosene), residual oil, natural gas and propane sales	25	%	25	%	23	%
Convenience store sales, rental income and sundry sales	4	%	1	%	1	%
Total	100	%	100	%	100	%

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. In 2015, we sold unbranded gasoline and diesel, including our proprietary premium brand, Diesel One®.

Crude Oil.  We engage in the purchasing, selling, storing 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 primarily divided into home heating oil, diesel and kerosene. In 2015, sales of home heating oil, diesel and kerosene accounted for approximately 54%, 44% and 2%, respectively, of our total volume of distillates sold. The distillates we sell are used primarily for fuel for trucks and off‑road construction equipment and for space heating of residential and commercial buildings.

We sell 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 2015, approximately 10% of the volume of home heating oil we sold to wholesale distributors was Heating Oil Plus™. In addition, we sell the additive used to create Heating Oil Plus™ to some wholesale distributors, 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.

In 2015, we sold home heating oil, including Heating Oil Plus™, to approximately 830 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 2015, approximately 33% 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 volume was sold on either a posted price or a price based on various indices which, in both instances, reflect current market conditions.

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 supply oil to industrial, commercial and marine customers. 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 and propane retailers and wholesale distributors primarily from our rail‑fed propane storage and distribution facility near our other terminal in Albany, New York.

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Convenience Store Items and Sundries.  We sell a broad selection of food, beverages, snacks, grocery and non‑food merchandise at our convenience store locations and generate sundry sales from car wash sales, lottery and ATM commissions at our convenience store locations.

Significant Customers

None of our customers accounted for greater than 10% of total sales for year ended December 31, 2015. We had one significant customer, ExxonMobil Corporation (“ExxonMobil”), that accounted for approximately 17% of our total sales for the year ended December 31, 2014 and 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.

Assets

Terminals

As of December 31, 2015, we owned, leased or maintained dedicated storage facilities at 25 bulk terminals, each with the capacity of more than 50,000 barrels, with a collective storage capacity of 12.2 million barrels. Twenty‑two of these bulk terminals are located throughout the Northeast. Some of our storage tankage is versatile, allowing us to switch tankage from one product to another.

In addition to refined products, we also own or operate four rail facilities in New York, Oregon and North Dakota capable of handling crude oil or ethanol and maintain dedicated storage at one other marine terminal in New York capable of handling crude oil. At select locations, we have capacity to store renewable fuels, and in Albany, New York, we also have an additional rail‑fed propane storage terminal.

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. We support our rail activity with a fleet of approximately 2,700 leased railcars. The makeup of this fleet is split between general‑purpose cars, typically used for light crude oil, ethanol and refined products, and coiled, insulated cars typically used for heavy crude oil and residual oil.

In connection with our business, we may lease or otherwise secure the right to use certain third-party assets (such as railcars, pipelines and barges).  We lease railcars through various lease arrangements with various expiration dates, and we lease barges through various time charter lease arrangement also with various expiration dates. We also have various pipeline connection agreements that extend from five to seven years beginning after the commissioning of the pipeline. Please read Note13, “Commitments and Contingencies,” for additional information on our railcar leases, barge leases and pipeline commitments.

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 customers) out of one of the terminals in our terminal network. Generally, both

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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.

Gasoline Stations

As of December 31, 2015, we had a portfolio of 1,509 owned, leased and/or supplied gasoline stations, including 281 convenience stores, primarily in the Northeast.

At our company‑operated stores, we operate the gasoline stations and convenience stores with our employees, and we set the retail price of gasoline at the station. At commission agent locations, we own the gasoline inventory, and we set the retail price of gasoline at the station and pay the commission agent a fee related to the gallons sold. We receive rental income from commission agent leased gasoline stations for the leasing of the convenience store premises, repair bays and other businesses that may be conducted by the commission agent. At dealer‑leased locations, the dealer purchases gasoline from us, and the dealer sets the retail price of gasoline at the dealer’s station. We also receive rental income from dealer‑leased gasoline stations and from cobranding arrangements. We also supply gasoline to independent contract dealers under agreements with the operators at these locations. Additionally, we have contractual relationships with distributors in certain New England states, pursuant to which we supply these distributors’ gasoline stations with ExxonMobil‑branded gasoline.

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 2015, we purchased an average of approximately 368,000 barrels per day of refined petroleum products, renewable fuels, crude oil, natural gas and propane. 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.

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 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 that we distribute. Therefore, our volumes in gasoline 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 volumes are generally higher during the first and fourth quarters of the calendar year. These factors may result in fluctuations in our quarterly operating results.

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, natural gas and propane. We endeavor to minimize commodity risk in connection with our daily operations through hedging by selling exchange‑traded futures contracts on regulated exchanges or using other over‑the‑counter 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 commodity product purchase and sales activities, we may experience net unbalanced positions for short periods of time as a result of variances in daily purchases and sales and transportation and delivery schedules as well as logistical issues inherent in the business, such as weather conditions. In

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connection with managing these positions, we are aided by maintaining a constant presence in the marketplace. We also engage in a controlled trading program for up to an aggregate of 250,000 barrels of commodity 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 may use foreign currency derivatives to minimize the risks of unfavorable exchange rates. These instruments may 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. Basis risk is the inherent market price risk created when a commodity of a 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 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 exchange-traded 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, the Chicago Mercantile Exchange (“CME”) and the Intercontinental‑Exchange (“ICE”), which are exchanges for the respective 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. 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 which is used for our bulk supply requirements 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 and diesel motor vehicle fuels, obligated parties must retire sufficient RINs to cover their Renewable Volume Obligation (“RVO”). Our U.S. Environmental Protection Agency (“EPA”) obligations relative to renewable fuel reporting are largely limited to the foreign gasoline that we may choose to import and a small amount of blending operations at certain facilities. As a wholesaler of transportation fuels through our 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 the RVO is a calendar year and the settlement of the RVO typically occurs by March 31 of the following year, the settlement of the RVO can occur, upon certain EPA deferral actions, more than one year after the close of the compliance period. Operating results are sensitive to the timing associated with our RIN position relative to our RVO at a point in time, and we may recognize a mark‑to‑market liability for 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 RVO as of the balance sheet date, we charge cost of sales for such deficiency based on the market price of the RINs as of the balance sheet date and record a liability representing our obligation to purchase RINs.

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For more information about our policies and procedures to minimize our exposure to market risk, including commodity market risk, please read Item 7A, “Quantitative and Qualitative Disclosures About Market Risk.”

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 supply oil to industrial, commercial and marine customers. We compete with other transloaders in our logistics activities including, in part, storage and transportation of crude oil, renewable fuels and gasoline 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 with respect to 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.

Employees

To carry out our operations, our general partner and certain of our operating subsidiaries employed approximately 1,890 full‑time employees as of December 31, 2015, of whichapproximately 100 employees were represented by labor unions under collective bargaining agreements with various expiration dates. We may not be able to renegotiate the collective bargaining agreements when they expire on satisfactory terms or at all. A failure to do so may increase our costs. In addition, existing labor agreements may not prevent a future strike or work stoppage, and any work stoppage could negatively affect our results of operations and financial condition. We believe we have good relations with our employees.

We have a shared services agreement with GPC. 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.”

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 GDSO 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®. We also have the following trademarks for our convenience store business: ALLTOWN®, YOUR TOWN.MYTOWN.ALLTOWN!®, CENTRE ST.KITCHEN®, Buck Stop®, Fast Freddie’s® and Mr. Mike’s®, and the pending trademark, ALLTOWN MARKET™. In connection with the January7, 2015 acquisition of Warren, we acquired the following trademarks owned by Drake Petroleum Company,Inc., an indirect wholly owned subsidiary of ours: Deli Joe’s®, Deli Joe’s logo, Diamond Fuels®, Xtra®, XtraCafé logo, Xtra Mart® and the Xtramart logo.

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Facilities

We lease office space for our principal executive office in Waltham, Massachusetts. This lease expires on July 31, 2026 with extension options through July31, 2036. In addition, we lease office space in Branford, Connecticut. This lease expires on July31, 2024 with extension options through July31, 2034.

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.

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 business, 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

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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 will not have a material adverse effect on our financial position, results of operations or cash available for distribution to our unitholders.

For additional information concerning certain environmental proceedings, please read Item3. “Legal Proceedings.”

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 EPA, and in some instances third parties, to act in response to threats to the public health or the environment and seek to recover from the responsible persons the costs they incur. It is possible for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. In the course of our ordinary operations, we may generate, store or otherwise handle materials and wastes that fall within the Superfund law’s definition of a hazardous substance and, as a result, we may be jointly and severally liable under the Superfund law for all or part of the costs required to clean up sites at which those hazardous substances have been released into the environment.

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

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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 various petroleum products and renewable fuels at our terminals, we are required to file spill response plans with either the U.S. Coast Guard (for marine facilities) and/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 products so regulated are 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 other products from above ground storage tanks. We believe we are in substantial compliance with these requirements.

Underground Storage Tanks

We are required to make financial expenditures to comply with regulations governing underground storage tanks (“USTs”) 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 USTs. 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 Clean Air Act (the “CAA”) 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 USTs. Compliance with existing and future environmental laws regulating UST systems of the kind we use may require significant capital expenditures in the future. These expenditures may include upgrades, modifications, and the replacement of USTs 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 may require permits for discharging pollutants into state and federal waters and impose substantial liabilities and remedial obligations for noncompliance. The EPA and the Army Corps of Engineers (“Corps”) released a rule to revise the definition of “waters of the United States” (“WOTUS”) for all Clean Water Act programs, which went into effect in August 2015. The U.S. Court of Appeals for the Sixth Circuit has stayed the WOTUS rule nationwide pending further action of the court. In response to this decision, the EPA and the Corps resumed nationwide use of the agencies’ prior regulations defining the term “waters of the United States.” Those regulations will be implemented as they were prior to the effective date of the new WOTUS rule. The WOTUS rule could significantly expand federal control of land and water resources across the United States, triggering substantial additional permitting and regulatory requirements. If the WOTUS rule survives judicial review in its current form, it could restrict exploration and production efforts by producers

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whose crude oil and other materials we transport. That restriction of supply could adversely affect our financial position, results of operations or cash available for distribution to our unitholders.

EPA regulations also may 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 CAA and comparable state and local laws, permits are typically required to emit regulated air pollutants into the atmosphere above certain thresholds. 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 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.

In November 2015, the EPA also revised the existing National Ambient Air Quality Standards (“NAAQS”) for ground‑level ozone, which made the standard more stringent. Nitrogen oxides and volatile organic compounds are recognized as pre‑cursors of ozone, and emissions of those materials are associated with mobile sources and the petroleum industry. The EPA has not yet designated which areas of the country are out of attainment with the new ground level ozone standard, and it will take the states several years to develop compliance plans for their non‑attainment areas. Several states have filed legal challenges to the new standard. If these challenges are unsuccessful, certain areas of the country previously in compliance with the various NAAQS, including areas where we operate, may be reclassified as non‑attainment. Such reclassification may make it more difficult to construct new or modified sources of air pollution in newly designated non‑attainment areas, or subject our existing operations to additional permitting requirements. While we are not able to determine the extent to which this new standard will impact our business at this time, it does have the potential to have a material impact on our operations and cost‑structure.

Climate Change

Federal climate change legislation in the United States appears unlikely in the near‑term. As a result, domestic efforts to curb greenhouse gas (“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 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

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products. Either of these events could have an adverse effect on our business. Likewise, in September 2015, the EPA proposed New Source Performance Standards for methane and volatile organic compound emissions from certain activities in the oil and gas sector, as well as a new definition of oil and gas sources, and new draft control guidance for reducing volatile organic compound emissions from existing oil and gas sources in certain ozone non‑attainment areas. If the rules are adopted as proposed, these rules could impose new compliance costs and permitting burdens on oil and gas operations, which could in turn affect the companies that produce the crude oil that we transport.  Currently, however, it is not possible to estimate the likely financial impact of potential future regulation on any of our sites.

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.

In August 2015, the EPA issued its final Clean Power Plan (“CPP”) rules that establish carbon pollution standards for power plants. Though the plan does not regulate hydraulic fracturing operations, it sets a national carbon pollution standard that is projected to cut emissions produced by U.S. power plants. The EPA expects each state to develop implementation plans for power plants in its state to meet the individual state targets established in the CPP, and has also proposed a federal compliance plan to implement the CPP in the event that approvable state plans are not submitted. Judicial challenges have been be filed, which seek a stay of the implementation of the rules. On February 9, 2016, the U.S. Supreme Court granted a stay of the implementation of the CPP before the U.S. Court of Appeals for the District of Columbia (“Circuit Court”) even issued a decision. By its terms, this stay will remain in effect throughout the pendency of the appeals process including at the Circuit Court and the Supreme Court through any certiorari petition that may be granted. The stay suspends the rule, including the requirement that states submit their initial plans by September 2016. The Supreme Court’s stay applies only to EPA’s regulations for CO₂ emissions from existing power plants and will not affect EPA’s standards for new power plants. It is not yet clear how the either the Circuit Court or the Supreme Court will rule on the legality of the CPP.

Overall, there has been a trend towards increased regulation of GHGs and initiatives, both domestically and internationally, to limit GHG emissions. Future efforts to limit emissions associated with transportation fuels and heating fuels could reduce the market for, or pricing of, our products, and thus adversely impact our business. In addition, 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.

Convenience Store Regulations

Our convenience store operations are subject to extensive governmental laws and regulations that include 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

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impact our retail price of cigarettes, cigarette unit volume and revenues, merchandise gross profit and overall customer traffic, which could in turn have a material adverse effect on our results of operations.

Ethanol Market

The market for ethanol is dependent on several economic incentives 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. 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 allow but do not require the introduction into commerce of gasoline that contains greater than 10 volume percent (“vol%”) ethanol and up to 15 vol% ethanol (“E15”) for use in model year 2001 and newer light‑duty motor vehicles, subject to certain conditions. E15 is not widely available in the United States 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 United States 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 2016, there were approximately 2,990 E85 stations in the United States.

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 store, sell and/or ship. 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 2015, TRIA has been extended through December 31, 2020. 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.

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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 and charter barges associated with the shipment of refined petroleum products, renewable fuels and crude oil. We conduct ongoing training programs to help ensure that our operations are in compliance with applicable regulations.

The trend in hazardous material transportation is to increase oversight and regulation of these operations. Several derailments of freight trains, including the tragic events in July 2013 in Lac Mégantic and other events, have led 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 ongoing 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. In August 2014, the U.S. Department of Transportation released a report finding that, based on the results of Operation Classification from August 2013 to May 2014, Bakken crude oil tends to be more volatile and flammable than other crude oils, and thus poses an increased risk for a significant accident. In April 2015, PHMSA and the Federal Railroad Administration (“FRA”) issued a number of additional safety advisories related to the operation of trains containing hazardous materials and flammable liquid.

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. In May 2015, PHMSA issued afinal rule that includes, among other things, additional requirements to enhance tank car standards for certain trains carrying crude oil and ethanol, a classification and testing program for crude oil, and a requirement that older DOT‑111 tank cars be phased out by as early as October 1, 2017 if they are not retrofitted to comply with new tank car design standards. The rule also includes a new braking standard for certain trains, designates new operational protocols for trains transporting large volumes of flammable liquids, such as routing requirements, speed restrictions and information for local government agencies, and provides new sampling and testing requirements to improve classification of energy products placed into transport. In addition, the FRA issued a notice and comment request in April 2015 providing notice that the agency wishes to collect more specific information concerning railcars carrying petroleum crude oil in any train involved in a reportable accident. 

In addition to action taken or proposed by federal agencies, some members of Congress have called for additional legislation regarding railcars carrying crude oil. In 2015, Congress has introduced several bills to place new emergency response and safety requirements on crude oil by rail operations. To date, none of these bills has been enacted into law. Likewise, a number of states proposed or enacted laws in 2015 that encourage safer rail operations or urge the federal government to strengthen requirements for these operations. The new PHMSA rule, and other potential future statutes or regulatory initiatives, may 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 these rulemakings will not be material to our business, financial condition or results of operations. Any such requirements would apply to the industry as a whole.

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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 sufficient funds are available to compensate victims and respond to the incident without making taxpayers fund any aspect of those efforts. In January 2014, 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. In April 2014, Transport Canada issued a protective order prohibiting oil shippers from using 5,000 of the DOT‑111 tank cars and imposing a three‑year phase‑out period for approximately 65,000 tank cars that do not meet certain safety requirements. Transport Canada also imposed a 50 mile‑per‑hour speed limit on trains carrying hazardous materials and required all crude oil shipments in Canada to have an emergency response plan. At the same time that PHMSA released its new rule, Canada’s Minister of Transport announced Canada’s new tank car standards, which largely align with the requirements in the PHMSA rule.

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 and regulations, including any voluntary measures by the rail industry, that result in new requirements for the design, construction or operation of tank cars used to transport crude oil, or, 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.

Item 1A. Risk Factors.

Risks Related to Our Business

We may not have sufficient cash from operations to enable us to 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 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;

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

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

· prevailing economic conditions.

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

· the level of capital expenditures we make;

· the restrictions contained in our credit agreement 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.

On January 28, 2016, we announced a reduction in the quarterly distribution for the fourth quarter of 2015 on all outstanding common units to $0.4625.  This distribution represented a decrease of 33.7% from the distribution of $0.6975 per unit paid in November 2015 and a decrease of 30.5% from the distribution of $0.6650 per unit paid in February 2015. The reduction in the distribution primarily reflected continuing weakness in the crude oil market.

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.

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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 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 or maintain distributions could be limited. We can give no assurance that our transaction efforts will be successful or that any such efforts 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 price, demand, 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 or maintain distributions may be reduced.

Our gasoline financial results are seasonal and can be 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 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

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the demand for gasoline that we distribute. Therefore, our results of operations in gasoline can be lower in the first and fourth quarters of the calendar year.

Our heating oil and residual oil financial results are seasonal and can be 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 can be 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.

A significant decrease in price or demand for the products we sell or a significant decrease in demand for our logistics activities could reduce our ability to make distributions to our unitholders.

A significant decrease in price or demand for the products we sell or a significant decrease in demand for our logisticsactivities could 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, natural gasand propane include:

· a recession or other adverse economic conditions or an increase in the market price or of an oversupply of refined petroleum products, renewable fuels, crude oil, natural gas 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, natural gas 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. Should we experience a reduction in our volumes stored, distributed and sold and in our related logistics activities, such costs and expenses may not decrease ratably or at all. 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, crude oil, natural gas and propane 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, crude oil, natural gas and propane price 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 future prices are higher than current prices, referred to as contango, we may use our storage capacity to improve our margins by

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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 future 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 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. A significant decrease in differentials could also have an adverse effect on our crude oil logistics activities and sales.

We have contractual obligations for certain transportation assets such as railcars, barges and pipelines.

We have obligations to satisfy contractual commitments for our railcars, barges and pipelines. A decline in demand for (i) the products we sell, including crude oil and ethanol, or (ii) our logistics activities, could result in a decrease in the utilization of thesetransportation assets, which could negatively impact our financial condition, results of operations and cash available for distribution to our unitholders. For example, during 2015, we experienced adverse market conditions in crude oil caused by an over-supplied crude oil market which resulted in tighter price differentials, and we experienced a reduction in our railcar movements but remained obligated to pay the applicable fixed charges for railcar leases.

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

As of December 31, 2015, our total debt, including amounts outstanding under our credit agreement and senior notes, was approximately $1.2billion. On February 24, 2016, we and certain of our subsidiaries entered into the fifth amendment to our credit agreement. We have the ability to incur debt, including the capacity to borrow up to $1.475 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

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· 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.

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.

Recently, global financial markets and economic conditions have been disrupted and volatile. The debt and equity capital markets have been exceedingly distressed. These issues, along with significant write‑offs in the financial services sector, the re‑pricing of credit risk and the economic conditions, 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.

Operating and financial restrictions and covenants in our credit agreement and the indentures governing our senior notes and borrowing base requirements in our credit agreement 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;

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· 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;

· 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

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· 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 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 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. If our swaps do not qualify for the commercial end‑user exception, or the cost of entering into uncleared swaps becomes prohibitive, we may be required to clear such transactions. The ultimate effect of the rules and any additional regulations on our business is uncertain at this time.

In addition, the Act requires that regulators establish margin rules for uncleared swaps. Banking regulators and the CFTC have adopted final rules establishing minimum margin requirements for uncleared swaps. Although we expect to qualify for the end‑user exception from such margin requirements for swaps entered into to hedge our commercial risks, the application of such requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. If any of our swaps do not qualify for the commercial end‑user exception, posting of 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 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

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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 and reduce our ability to monetize or restructure our existing derivative contracts. 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 unfavorable market conditions which can adversely affect our financial condition, results of operations and cash available for distribution to our unitholders. In addition, any noncompliance with our risk management policies could result in significant financial losses.

While our hedging policies are designed to minimize commodity risk, some degree of exposure to unforeseen fluctuations in market conditions remains. For example, we change our hedged position daily in response to movements in our inventory. If we overestimate or underestimate our sales from inventory, we may be unhedged for the amount of the overestimate or underestimate. Also, significant increases in the costs of 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 is 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, 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

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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, natural gas 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, natural gas 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 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 have been volatile. General political conditions, acts of war, terrorism and instability in oil producing regions, particularly in the United States, Canada, Middle East, Russia, Africa and South America, could significantly impact crude oil supplies and crude oil and refined petroleum product 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 customers’ 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.

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.

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 number of new legal incentives and regulatory requirements, and executive initiatives, including the CPP and various government subsidies including the extension of certain tax credits for renewable energy, have made these alternative forms of energy more competitive. 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

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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.

Erosion of the value of major gasoline brands could adversely affect our gasoline sales and customer traffic.

As a significant number of our retail gasoline stations and convenience stores are branded Mobil or other major gasoline brands, they may be dependent, in part, upon the continuing favorable reputation of such brands. Erosion of the value of major gasoline brands 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 upon which could affect the flow of service. If any of those effects were to occur, they could have an adverse effect on transportation services, and thus our operations. In addition, accidents, labor disputes between providers and their employees and labor renegotiations, including strikes, lockouts or a work stoppage, shortage of railcars, mechanical difficulties or bottlenecks and disruptions in transportation logistics could also disrupt our business. 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 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.

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, natural gas 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.

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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 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 price competition and the availability of alternative and less expensive fuels.

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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. As of December 31, 2015, we leased the entirety of two bulk terminals that we operated exclusively for our business and operated and maintained dedicated storage facilities at another 18bulk terminals. The lease agreements governing these arrangements are subject to expiration at various dates through 2019. These arrangements may not be renewed when they expire or, if renewed, may not be renewed at rates and on terms at least as favorable. If these agreements are not renewed or we are unable to renew these agreements at rates and on terms at least as favorable, it could have an adverse effect on our financial condition, results of operations and cash available for distribution to our unitholders.

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.

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 may lease certain sites where the rent expense we pay is more than the lease payments we collect.  We cannot provide any assurance that our gross margin from the sale of transportation fuels and related convenience store items at 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.

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 decreases in demand for refined petroleum products, renewable fuels, crude oil, natural gas 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,

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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 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 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 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. The federal government recently finalized a rule including new design and construction requirements for railroad tank cars that are used to transport crude oil and ethanol. The establishment of more stringent design or construction requirements for railroad tank cars that are used to transport crude oil and ethanol with too short of a timeframe for compliance may lead to shortages of compliant railcars available to transport crude oil and ethanol, which could adversely affect our business. Likewise, some environmental interest groups have commenced efforts to seek to use state and local laws to restrict the types of railroad tanks cars that can be used to deliver crude oil to petroleum bulk storage terminals. Were such state and local laws to come into effect and were they to survive appeals and judicial review, they would potentially expose our operations to duplicative and possibly inconsistent regulation.

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 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. Similarly, many of our suppliers face a trend of increasing environmental regulations, which could likewise restrict their ability to produce crude oil or fuels, or increase their costs of production, and thus impact the price of, and/or their ability to deliver, these products.

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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 GHGs, might adversely affect our products and activities, including the storage of refined petroleum products, renewable fuels, crude oil and propane, as well as our waste management practices and our control of air emissions. Enactment of laws and passage of regulations regarding GHG emissions, or other actions to limit GHG 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 GHG 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 GHGs 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 CAA. 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 GHGs, 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.”

There are many regulatory approaches currently in effect or being considered to address GHGs, 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. For example, the EPA recently released the CPP to reduce CO₂ emissions from power plants, which is currently subject to a judicial stay. In addition, at the 2015 United Nations Framework Convention on Climate Change in Paris, the United States and nearly 200 other nations entered into an international climate agreement. Although this agreement does not create any binding obligations for nations to limit their GHG emissions, it does include pledges to voluntarily limit or reduce future emissions. Future international, federal and state initiatives, or an unfavorable outcome in the CPP judicial challenge, 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

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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 railcars that we lease. 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. 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. A final rule promulgated by PHMSA in May 2015 requires, among other things, enhanced tank car standards, a classification and testing program for crude oil, and a phase‑out date by as early as October 2017 for older DOT‑111 tank cars that are not retrofitted. The rule also includes a new braking standard for certain trains, designates new operational protocols for trains transporting large volumes of flammable liquids, such as routing requirements, speed restrictions, and information for local government agencies, and provides new sampling and testing requirements to improve classification of energy products placed into transport. At the same time that PHMSA released its new rule, Canada’s Minister of Transport announced Canada’s new tank car standards, which largely align with the requirements in the PHMSA rule. In addition, Transport Canada has also issued emergency directives and ministerial orders relating to train speed restrictions, route risk analyses, and a phase out of non‑compliant DOT 111 tank cars.

Any changes to the existing laws and regulations, or promulgation of new laws and regulations, including any voluntary measures by the rail industry, that result in new requirements for the design, construction or operation of tank cars used to transport crude oil may require us to make expenditures to comply with new standards that are material to our operations, and, to the extent that new regulations require design changes or other modifications of tank cars, we may incur significant constraints on transportation capacity during the period while tank cars are being retrofitted or newly constructed to comply with the new regulations. We cannot assure that the totality of costs incurred to comply with any new standards and regulations and any impacts on our operations will not be material to our business, financial condition or results of operations. In addition, 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 against such events, we cannot assure you that our policies will cover the entirety of any damages that may arise from such an event.

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

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 USTs are subject to federal and state regulations and legislation. Compliance

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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 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. In addition to the threat of terrorist attacks, we face various other security threats, including cyber security threats to gain unauthorized access to sensitive information or systems or to render data or systems unusable; threats to the safety of our employees; threats to the security of our facilities, such as terminals and pipelines, and infrastructure or third‑party facilities and infrastructure. These developments have subjected our operations to increased risks.

Although we utilize various procedures and controls to monitor these threats and mitigate our exposure to security threats, there can be no assurance that these procedures and controls will be sufficient in preventing security threats from materializing. If any of these events were to materialize, they could lead to losses of sensitive information, critical infrastructure, personnel or capabilities, essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations, or cash flows. Cyber security attacks in particular are evolving and include malicious software, attempts to gain unauthorized access to, or otherwise disrupt, our pipeline control systems, attempts to gain unauthorized access to data, and other electronic security breaches that could lead to disruptions in critical systems, including our pipeline control systems, unauthorized release of confidential or otherwise protected information and corruption of data. These events could damage our reputation and lead to financial losses from remedial actions, loss of business or potential liability.

We incur 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, natural gas 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 purchase 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

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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.

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 AE Holdings Corp.”

We depend on unionized labor for the operation of certain of our terminals. Any work stoppages or labor disturbances at these terminals 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 could permit them to favor their own interests to the detriment of our unitholders.

As of February25, 2016, affiliates of our general partner, including directors and executive officers and their affiliates, owned 21.9% 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 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

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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. Please read “—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.

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Please read Item 13, “Certain Relationships and Related Transactions, and Director Independence—Omnibus Agreementand Business Opportunity Agreement.”

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

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

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

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

· generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general partner and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or be “fair and reasonable” to us and that, in determining whether a transaction or resolution is “fair and reasonable,” our general 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 the consent of the holders of at least 66 2/3% of the outstanding units (including units held by our general partner and its affiliates), which could lower the trading price of our common units.

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. The vote of the holders of at least 66 2/3% of all outstanding common units (including units held by our general partner and its affiliates) is required 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.

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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.

A substantial number of our securities may be sold in the future either pursuant to Rule 144 under 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.

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.

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

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

Like all equity investments, an investment in our common units is subject to certain risks. In exchange for accepting these risks, investors may expect to receive a higher rate of return than would otherwise be obtainable from lower‑risk investments. Accordingly, as interest rates rise, the ability of investors to obtain higher risk‑adjusted rates of return by purchasing government‑backed debt securities may cause a corresponding decline in demand for riskier investments generally, including yield‑based equity investments such as publicly‑traded limited partnership interests. Reduced demand for our common units resulting from investors seeking other more favorable investment opportunities may cause the trading price of our common units to decline.

Our general partner has a limited call right that may require unitholders to sell their common units at an undesirable time or price.

If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then‑current market price. As a result, unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on their investment. Unitholders may also incur a tax liability upon a sale of their units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the limited call right. There is no restriction in our partnership agreement that prevents our general partner from issuing additional common units and exercising its call right. If our general partner exercises its limited call right, the effect

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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.

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.

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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. Richard Slifka and his 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. Richard Slifka,  Eric Slifka and Andrew 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 andBusiness 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.

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 distributions, 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.

At the state level, several states have been evaluating ways to independently 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 or an increase in the existing tax rates would reduce the cash available for distribution to our unitholders. 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.

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

The present U.S. 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, the Obama administration’s budget proposal for fiscal year 2017recommends that certain publicly traded partnerships earning income from activities related to fossil fuels be taxed as corporations beginning in 2022. From time to time, members of Congress propose and consider such substantive changes to the existing federal income tax laws that affect publicly traded partnerships.  If successful, the Obama administration’s proposal or other similar proposals could eliminate 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.

In addition, on May5, 2015, the IRS issued proposed regulations concerning which activities give rise to qualifying income within the meaning of Section7704 of the Internal Revenue Code. We do not believe the proposed regulations affect our ability to qualify as a publicly traded partnership. However, finalized regulations could modify the amount of our gross income that we are able to treat as qualifying income for the purposes of the qualifying income requirement.

Any modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.

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 subsidiaries that are treated as corporations for federal income tax purposes and subject to corporate‑level income taxes.

As of December 31, 2015, we conducted substantially all of our operations of our end‑user business through six subsidiaries that are treated as corporations for federal income tax purposes. These corporations engage in the retail sale of gasoline and/or operates convenience stores and collect rents on personal property leased to dealers and commissioned agents at other stations. Five of these corporations include Warren and its subsidiaries which we acquired in January 2015. We may elect to 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. Recently enacted legislation alters the procedures for assessing and collecting taxes due for taxable years beginning after December 31, 2016, in a manner that could substantially reduce cash available for distribution to you.

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.

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Recently enacted legislation, applicable to us for taxable years beginning after December 31, 2017, alters the procedures for auditing large partnerships and also alters the procedures for assessing and collecting taxes due (including applicable penalties and interest) as a result of an audit. Under the new rules, unless we are eligible to, and do, elect to issue revised Schedules K-1 to our partners with respect to an audited and adjusted return, the IRS may assess and collect taxes (including any applicable penalties and interest) directly from us in the year in which the audit is completed. If we are required to pay taxes, penalties and interest as the result of audit adjustments, cash available for distribution to our unitholders may be substantially reduced. In addition, because payment would be due for the taxable year in which the audit is completed, unitholders during that taxable year would bear the expense of the adjustment even if they were not unitholders during the audited taxable year.

Even if our unitholders do not receive any cash distributions from us, they will be required to pay taxes on their share of our taxable income.

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.For example, if we sell assets and use the proceeds to repay existing debt or fund capital expenditures, you may be allocated taxable income and gain resulting from the sale and our cash available for distribution would not increase. Similarly, taking advantage of opportunities to reduce our existing debt, such as debt exchanges, debt repurchases, or modifications of our existing debt could result in “cancellation of indebtedness income” being allocated to our unitholders as taxable income without any increase in our cash available for distribution. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the tax liability that results from that income.

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. 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.

A substantial portion of the amount realized from the sale of units by an investor, whether or not representing gain, may be taxed as ordinary income to the holder due to potential recapture items, including depreciation recapture. Thus, a unitholder may recognize both ordinary income and capital loss from the sale of his units if the amount realized on a sale of such units is less than such unitholder’s adjusted basis in the units. Net capital loss may only offset capital gains and, in the case of individuals, up to $3,000 of ordinary income per year. In the taxable period in which a unitholder sells his units, the unitholder may recognize ordinary income from our allocations of income and gain to him prior to the sale and from recapture items that generally cannot be offset by any capital loss recognized upon the sale of units.

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. Allocations and/or distributions to non‑U.S. persons will be subject to withholding taxes imposed at the highest effective 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 share 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 common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred. The U.S. Department of the Treasury recently adopted final Treasury Regulations allowing a similar monthly simplifying convention for taxable years beginning on or after August3, 2015. However, such regulations do not specifically authorize the use of the proration method we have adopted and may not specifically authorize all aspects of our proration method thereafter. If the IRS were to challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

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

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

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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 constructive 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 for one calendar year and could 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. The IRS has announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests and the IRS grants special relief, among other things, the partnership may be permitted to provide only a single Schedule K-1 to unitholders for the two short tax periods included in the year in which the termination occurs.

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

In addition to federal income taxes, unitholders will likely be subject to other taxes, including state, local and non‑U.S. taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if they do not live in any of those jurisdictions. Unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. As of December 31, 2015, we conducted business in 36 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.

On May 16, 2014, we received a subpoena from the SEC requesting information for relevant time periods primarily relating to our accounting for Renewable Identification Numbers and the restatement of our consolidated financial statements as of and for the quarters ended March 31, 2013, June 30, 2013 and September 30, 2013. We have produced responsive materials to the SEC and intend to continue to cooperate fully with the SEC.

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 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

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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 June 2015 acquisition of retail gasoline stations from Capitol, we assumed certain environmental liabilities, including future remediation activities required by applicable federal, state or local law or regulation at certain of the retail gasoline stations owned by Capitol. Certain environmental remediation obligations at most of the acquired retail gasoline station assets from Capitol are being funded by third parties who assumed certain liabilities in connection with Capitol’s acquisition of these assets from ExxonMobil in 2009 and 2010 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, a total environmental liability of approximately $0.3 million for those locations not covered by third parties.

In connection with the January 2015 acquisition of the Revere Terminal, we assumed certain environmental liabilities, including certain ongoing environmental remediation efforts. As a result, we recorded, on an undiscounted basis, a total environmental liability of approximately $3.1 million.

In connection with the January 2015 acquisition of Warren, we assumed certain environmental liabilities, including certain ongoing environmental remediation efforts at certain of the retail gasoline stations owned by Warren and future remediation activities required by applicable federal, state or local law or regulation. As a result, we recorded, on an undiscounted basis, a total environmental liability of approximately $36.5 million.

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

In connection with the March 2012 acquisition of Alliance Energy LLC (“Alliance”), we assumed Alliance’s environmental liabilities, including ongoing environmental remediation at certain of the retail gasoline 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 initially 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, 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 initially recorded, on an undiscounted basis, total environmental liabilities of approximately $30.0 million.

In addition to the above-mentioned environmental liabilities related to our retail gasoline stations, we retain environmental obligations associated with certain gasoline stations that we have sold.

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 that are coordinated

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with and approved by the state environmental agency. As a result, we initially recorded, on an undiscounted basis, a total environmental liability of approximately $1.5 million.

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

Other

In February 2016, we received a request for information from the EPA seeking certain information regarding the Albany Terminal in order to assess its compliance with the CAA. The information requested generally relates to crude oil received by, stored at and shipped from our petroleum product transloading facility in Albany, New York (the “Albany Terminal”),including its composition, control devices for emissions and various permitting-related considerations. The Albany Terminal is a 63-acre licensed, permitted and operational stationary bulk petroleum storage and transfer terminal that currently consists of petroleum product storage tanks, along with truck, rail and marine loading facilities, for the storage, blending and distribution of various petroleum and related products, including, but not limited to, gasoline, ethanol, distillates, heating and crude oils. We intend to cooperate fully with the agency and believe the responsive information will demonstrate that our operations at the Albany Terminal are in compliance with all pertinent requirements.

By letter dated October 5, 2015, we received a notice of intent to sue (“October NOI”), which supersedes and replaces a prior notice of intent to sue that we received on September 1, 2015 (the “September NOI”) from Earthjustice, an environmental advocacy organization on behalf of the County of Albany, New York, a public housing development owned and operated by the Albany Housing Authority and certain environmental organizations, related to alleged violations of the CAA at our Albany Terminal, particularly with respect to crude oil operations at the Albany Terminal. The October NOI revises the superseded and replaced September NOI to add two additional environmental advocacy organizations and to revise the relief sought and the description of the alleged CAA violations.

On February3, 2016, Earthjustice and the other entities identified in the October NOI filed suit against us in federal court in Albany under the citizen suit provisions of the CAA. In summary, this lawsuit alleges that our operations at the Albany Terminal are in violation of the CAA. The plaintiffs seek, among other things, relief that would compel us both to apply for what they contend is the applicable permit under the CAA, and to install additional pollution controls. In addition, the plaintiffs seek to prohibit the Albany Terminal from receiving, storing, handling, and marine loading certain types of Bakken crude oil and to require payment of a civil penalty of $37,500 for each day we operated the Albany Terminal in violation of the CAA. We believe that we have meritorious defenses against all allegations and will vigorously contest this lawsuit.

On May 29, 2015 and in connection with a commercial dispute with Tethys Trading Company LLC (“Tethys”), we received a notice from Tethys alleging a default under, and purporting to terminate, our contract with Tethys for crude oil services at our Oregon facility. However, we do not believe Tethys had the right to terminate the contract, and we will take appropriate action to enforce our rights under the agreement. We had expected to receive fees from this contract of approximately $13.2 million for the period July 1, 2015 through December 31, 2015 and approximately $105.2 million in the aggregate for the remaining four years of the contract.

On March 26, 2015, we received a Notice of Non-Compliance (“NON”) from the Massachusetts Department of Environmental Protection (“DEP”) with respect tothe Revere Terminal, alleging certain violations of the National Pollutant Discharge Elimination System Permit (“NPDES Permit”) related to storm water discharges. The NON requires us to submit a plan to remedy the reported violations of the NPDES Permit. We have responded to the NON with a plan and are implementing modifications to the storm water management system at the Revere Terminal. We have determined that compliance with the NON and implementation of the plan will have no material impact on our operations.

We have a dispute with Lansing Ethanol Services, LLC (“Lansing”) for damages in excess of $12.0 million. The dispute involves Lansing’s failure to transfer Renewable Fuel Identification Numbers to us in connection with certain agreements for the purchase and sale of ethanol. The parties have agreed to arbitrate under the rules of the American Arbitration Association. We filed for arbitration on March 24, 2015 and anticipate arbitration to commence

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during the first quarter ending March31, 2016. We believe we have meritorious positions and intend to vigorously pursue a favorable result in connection with this dispute.

On July 2, 2014, a lawsuit was filed by the Northwest Environmental Defense Center and other environmental non‑government organizations (the “Plaintiffs”) against us and Cascade Kelly Holdings LLC (“Cascade Kelly”) alleging violations of the CAA. The suit, filed in the United States District Court for the district of Oregon, alleged that Cascade Kelly was operating without the proper permit under the applicable rules. The lawsuit sought penalties, injunctive relief and reimbursement of attorneys’ fees. A trial was held during the fourth quarter of 2015.On December30, 2015, the Court issued a judgment in our favor and dismissed the case with prejudice. The time for requesting an appeal has passed and the Plaintiffs did not appeal. Accordingly, the case is closed.

On May 16, 2014, we received a subpoena from the SEC requesting information for relevant time periods primarily relating to our accounting for Renewable Identification Numbers and the restatement of our consolidated financial statements as of and for the quarters ended March 31, 2013, June 30, 2013 and September 30, 2013. We intend to continue to cooperate fully with, and have produced responsive materials to, the SEC.

We received letters from the EPA dated November 2, 2011 and March 29, 2012, containing requirements and testing orders (collectively, the “Requests for Information”) for information under the CAA. The Requests for Information were part of an EPA investigation to determine whether we have violated sections of the CAA at certain of our terminal locations in New England with respect to residual oil and asphalt. On June 6, 2014, a Notice of Violation (the “NOV”) was received from the EPA, alleging certain violations of its Air Emissions License issued by the Maine Department of Environmental Protection, based upon the test results at the South Portland, Maine terminal. We met with and provided additional information to the EPA with respect to the alleged violations. On April 7, 2015, the EPA issued a Supplemental Notice of Violation (the “Supplemental NOV”) modifying the allegations of violations of the terminal’s Air Emissions License. We have responded to the Supplemental NOV and engaged in further negotiations with the EPA. A tolling agreement was executed with the United States on December1, 2015, and negotiations are continuing in the first quarter of 2016. While we do not believe that a material violation has occurred, and we contest the allegations presented in the NOV and Supplemental NOV, we do not believe any adverse determination in connection with the NOV 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 February25, 2016 was $13.26. At the close of business on February25, 2016, based upon information received from our transfer agent and brokers and nominees, we had 11,904 common unitholders, including beneficial owners of common units held in street name. The following table sets forth the range of the daily high and low sales prices per common unit as quoted on the New York Stock Exchange and the cash distributions per common unit for the periods indicated.

	Price Range
					Cash Distribution
	High		Low		Per Common Unit (a)
2015
Fourth Quarter	$	35.00	$	14.80	$	0.4625
Third Quarter		35.67		26.55		0.6975
Second Quarter		42.74		32.01		0.6925
First Quarter		40.37		32.68		0.6800
2014
Fourth Quarter	$	45.75	$	30.45	$	0.6650
Third Quarter		45.00		37.43		0.6525
Second Quarter		43.41		36.58		0.6375
First Quarter		40.50		33.54		0.6250

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

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 in certain circumstances.

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, to comply with applicable law, any of our debt instruments or other agreements, or to provide funds for distributions to unitholders and 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: 99.33% to the common unitholders, pro rata, and 0.67% 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
	Total Quarterly Distribution	Interest in Distributions
	Target Amount	Unitholders		General Partner
First Target Distribution	upto $0.4625	99.33	%	0.67	%
Second Target Distribution	above $0.4625 up to $0.5375	86.33	%	13.67	%
Third Target Distribution	above $0.5375 up to $0.6625	76.33	%	23.67	%
Thereafter	above $0.6625	51.33	%	48.67	%

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

We did not repurchase any of our common units during the quarter ended December 31, 2015.

Item 6. Selected Financial Data.

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

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

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comparable financial measures calculated in accordance with GAAP in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations—Key Performance Indicators.”

	Year Ended December 31,
	2015			2014			2013			2012			2011
	(dollars in millions except per unit amounts)
Statement of Income Data:
Sales	$	10,314.9		$	17,269.9		$	19,589.6		$	17,626.0		$	14,835.7
Cost of sales		9,717.2			16,725.1			19,185.1			17,291.9			14,625.9
Gross profit		597.7			544.8			404.5			334.1			209.8
Selling, general and administrative expenses		177.0			154.0			115.5			95.7			73.9
Operating expenses		290.3			204.1			185.7			140.4			73.5
Restructuring charges		—			—			—			—			2
Amortization expense		13.5			18.9			19.2			7.0			4.8
Loss (gain) on sale and disposition of assets		2.1			2.2			(1.3)			0.6			0.2
Total operating costs and expenses		482.9			379.2			319.1			243.7			154.4
Operating income		114.7			165.6			85.4			90.3			55.4
Interest expense		(73.3)			(47.7)			(43.5)			(42.0)			(35.9)
Income before income tax expense		41.4			117.9			41.9			48.3			19.4
Income tax benefit (expense)		1.9			(0.9)			(0.9)			(1.6)			—
Net income		43.3			117.0			41.0			46.7			19.4
Net loss (income) attributable to noncontrolling interest (1)		0.3			(2.3)			1.6			—			—
Net income attributable to Global Partners LP		43.6			114.7			42.6			46.7			19.4
Less: General partners’ interest in net income		7.7			6.0			3.5			1.2			0.7
Limited partners’ interest in net income	$	35.9		$	108.7		$	39.1		$	45.5		$	18.7
Per Unit Data
Basic net income per limited partner unit (2)	$	1.12		$	3.97		$	1.43		$	1.73		$	0.88
Diluted net income per limited partner unit (2)	$	1.11		$	3.95		$	1.42		$	1.71		$	0.87
Cash distributions per limited partner unit (3)	$	2.74		$	2.53		$	2.34		$	2.06		$	2.00
Cash Flow Data:
Net cash provided by (used in)
Operating activities	$	62.5		$	344.9		$	255.1		$	232.4		$	(17.4)
Investment activities	$	(649.7)		$	(91.1)		$	(243.2)		$	(226.5)		$	(13.4)
Financing activities	$	583.1		$	(257.8)		$	(8.7)		$	(4.3)		$	32.7
Other Financial Data:
EBITDA (4)	$	225.7		$	242.3		$	157.4		$	135.8		$	85.7
Distributable cash flow (5)	$	126.9		$	161.2		$	105.2		$	80.8		$	46.7
Capital expenditures—acquisitions (6)	$	561.2		$	—		$	185.3		$	188.7		$	—
Capital expenditures—maintenance and expansion (6)	$	92.9		$	95.1		$	67.1		$	44.9		$	16
Operating Data:
Normal heating degree days (7)		5,630			5,630			5,630			5,661			5,630
Actual heating degree days		5,651			5,664			5,521			4,754			5,137
Variance from normal heating degree days		0.37	%		1	%		(2)	%		(16)	%		(9)	%
Variance from prior year actual degree days		(0.23)	%		3	%		16	%		(7)	%		2	%
Total gallons sold (in millions)		5,648			6,356			6,956			6,100			5,217
Variance in volume sold from prior year		(11)	%		(9)	%		14	%		17	%		43	%
Balance Sheet Data (at period end):
Total assets	$	2,663.7		$	2,030.8		$	2,425.9		$	2,329.8		$	1,876.6
Long—term debt (8)	$	1,075.6		$	593.9		$	910.0		$	762.8		$	731.1
Total debt	$	1,173.7		$	594.6		$	913.7		$	846.5		$	793.9
Total liabilities	$	1,969.7		$	1,394.7		$	1,962.7		$	1,893.3		$	1,561.3
Partners’ equity	$	694.0		$	636.1		$	463.2		$	436.5		$	315.3

The above table reflects certain rounding conventions.

(1) On February 1, 2013, we acquired a 60% membership interest in Basin Transload, LLC (“Basin Transload”). The net income (loss)in the table above 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.

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(3) 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.

(4) 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.”

(5) 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.”

(6) Capital expenditures are discussed under “Liquidity and Capital Resources” in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

(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.”

(8) As of December 31, 2015, we adopted the updated accounting guidance that requires debt issuance costs to be presented as a direct deduction from the associated debt obligation. As a result, we reclassified unamortized debt issuance costs from prepaid expenses and other current assets and other assets to a reduction of long-term debt as of December 31, 2014 and 2013. This standard is not applicable for the other periods presented.

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

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

Overview

General

We are a midstream logistics and marketing company engaged in the purchasing, selling, storing and logistics of transporting petroleum and related products, including domestic and Canadian crude oil, gasoline and gasoline blendstocks (such as ethanol), distillates (such as home heating oil, diesel and kerosene), residual oil, renewable fuels, natural gas and propane. We also receive revenue from convenience store sales and gasoline station rental income. We own, control or have access to one of the largest terminal networks of refined petroleum products and renewable fuels in the Northeast. We own transload and storage terminals in North Dakota and Oregon that extend our origin‑to‑destination capabilities from the mid‑continent region of the United States and Canada to the East and West Coasts. We are one of the largest distributors of gasoline, distillates, residual oil and renewable fuels to wholesalers, retailers and commercial customers in the New England states and New York. As of December 31, 2015, we had a portfolio of 1,509 owned, leased and/or supplied gasoline stations, including 281 directly operated convenience stores, in the Northeast, Maryland and Virginia.

Collectively, we sold approximately $9.9 billion of refined petroleum products, renewable fuels, crude oil, natural gas and propane for the year ended December 31, 2015. In addition, we had other revenues of approximately $0.4 billion, primarily from convenience store sales at our directly operated stores and rental income from dealer leased or commission agent leased gasoline stations and from cobranding arrangements.

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.

Operating Segments

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. We operate our business under three segments: (i) Wholesale, (ii) Gasoline Distribution and Station Operations (“GDSO”) and (iii) Commercial. In 2015, our Wholesale, GDSO and Commercial sales accounted for approximately 57%, 36% and  7% of our total sales, respectively.

Wholesale

In our Wholesale segment, we engage in the logistics of selling, gathering, storage and transportation of refined petroleum products, renewable fuels, crude oil and propane. We sell branded and unbranded gasoline and gasoline blendstocks and diesel to wholesale distributors.We transport these products by railcars, barges and/or pipelines pursuant to spot or long-term contracts. We aggregate crude oil by truck or pipeline in the mid-continent region of the United States and Canada, transport it by train and ship it by barge to refiners on the East and West Coasts. We sell home heating oil, diesel, kerosene, residual oil and propane to home heating oil and propane retailers and wholesale distributors. Generally, customers use their own vehicles or contract carriers to take delivery of the gasoline and distillates at bulk terminals and inland storage facilities that we own or control or at which we have throughput or exchange arrangements. Ethanol is shipped primarily by rail and by barge.

In our Wholesale segment, we obtain Renewable Identification Numbers (“RINs”) in connection with our purchase of ethanol which is used for bulk trading purposes or for blending with gasoline through our terminal system. A

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RIN is a renewable identification number associated with government‑mandated renewable fuel standards. To evidence that the required volume of renewable fuel is blended with gasoline, obligated parties must retire sufficient RINs to cover their Renewable Volume Obligation (“RVO”). Our EPA obligations relative to renewable fuel reporting are largely limited to the foreign gasoline that we may choose to import.

Gasoline Distribution and Station Operations

In our GDSO segment, gasoline distribution includes sales of branded and unbranded gasoline to gasoline station operators and sub-jobbers. Station operations include (i)convenience stores, (ii)rental income from gasoline stations leased to dealers,from commissioned agents and from cobranding arrangements,  and (iii)sundries (such as car wash sales, lottery and ATM commissions). The results of Warren and Capitol are included in the GDSO segment.

As of December 31, 2015, we had a portfolio of owned, leased and/or supplied gasoline stations, primarily in the Northeast, that consisted of the following:

Company operated	281
Commissioned agents	283
Lessee dealers	280
Contract dealers	665
Total	1,509

At our company‑operated stores, we operate the gasoline stations and convenience stores with our employees, and we set the retail price of gasoline at the station. At commission agent locations, we own the gasoline inventory, and we set the retail price of gasoline at the station and pay the commission agent a fee related to the gallons sold. We receive rental income from commission agent leased gasoline stations for the leasing of the convenience store premises, repair bays and other businesses that may be conducted by the commission agent. At dealer‑leased locations, the dealer purchases gasoline from us, and the dealer sets the retail price of gasoline at the dealer’s station. We also receive rental income from dealer‑leased gasoline stations and from cobranding arrangements. We also supply gasoline to independent contract dealers under agreements with the operators at these locations. Additionally, we have contractual relationships with distributors in certain New England states, pursuant to which we supply these distributors’ gasoline stations with ExxonMobil‑branded gasoline.

Commercial

In our Commercial segment, we include 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, bunker fuel and natural gas. In the case of public sector commercial and industrial end user customers, we sell products primarily either through a competitive bidding process or through contracts of various terms. We generally arrange for the delivery of the product to the customer’s designated location, and we respond to publicly‑issued requests for product proposals and quotes. Our Commercial segment also includes sales of custom blended fuels delivered by barges or from a terminal dock to ships through bunkering activity.

For the years ended December 31, 2015, 2014 and 2013, our Commercial 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 our Commercial segment as we believe such disclosures are meaningful to users of our financial information.

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 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 that we distribute. Therefore, our volumes in gasoline 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

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and residual oil for space heating purposes, is generally greater during the winter months, heating oil and residual oil volumes are generally higher during the first and fourth quarters of the calendar year. These factors may result in fluctuations in our quarterly operating results.

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, crude oil, natural gas and propane 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, crude oil, natural gas and propane,  price 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 future 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 future 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 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 domestic crude oil production which, in turn, could have an adverse effect on our crude oil logistics activities and sales. A significant decrease in differentials could alsohave an adverse effect on our crude oil logistics activities and sales.In addition, any prolonged decline in crude oil prices and differentials may become an indicator of the potential impairment of our long-lived assets used at our crude oil transloading terminals in North Dakota and/or goodwill within our crude oil business in our Wholesale reporting unit. 

· On January 28, 2016, we announced a reduction in the quarterly distribution for the fourth quarter of 2015 on all outstanding common units to $0.4625.  This distribution represented a decrease of 33.7% from the distribution of $0.6975 per unit paid in November 2015 and a decrease of 30.5% from the distribution of $0.6650 per unit paid in February 2015. The reduction in the distribution primarily reflected continuing weakness in the crude oil market. The significant decline in the price of crude oil and tight crude oil differentials negatively impacted our fiscal 2015 results.

· 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

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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 or maintain distributions could be limited. We can give no assurance that our transaction efforts will be successful or that any such efforts 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 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 upon which could affect the flow of service. In addition, accidents, labor disputes between the railroads and their employees and labor renegotiations, including strikes, lockouts or a work stoppage, shortage of railcars, mechanical difficulties or bottlenecks and disruptions in railroad logistics 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.

· We have contractual obligations for certain transportation assets such as railcars, barges and pipelines. A decline in demand for (i) the products we sell, including crude oil and ethanol, or (ii) our logistics activities, could result in a decrease in the utilization of these transportation assets, which could negatively impact our financial condition, results of operations and cash available for distribution to our unitholders. For example, during 2015, we experienced adverse market conditions in crude oil caused by an over-supplied crude oil market which resulted in tighter price differentials, and we experienced a reduction in our railcar movements but remained obligated to pay the applicable fixed charges for railcar leases.

· Our gasoline financial results are seasonal and can be 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 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 that we distribute. Therefore, our results of operations in gasoline can be lower in the first and fourth quarters of the calendar year.

· Our heating oil and residual oil financial results are seasonal and can be 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 can be 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

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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 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 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. The federal government recently finalized a rule including new design and construction requirements for railroad tank cars that are used to transport crude oil and ethanol. The establishment of more stringent design or construction requirements for railroad tank cars that are used to transport crude oil and ethanol with too short of a timeframe for compliance may lead to shortages of compliant railcars available to transport crude oil and ethanol, which could adversely affect our business. Likewise, some environmental interest groups have commenced efforts to seek to use state and local laws to restrict the types of railroad tanks cars that can be used to deliver crude oil to petroleum bulk storage terminals. Were such state and local laws to come into effect and were they to survive appeals and judicial review, they would potentially expose our operations to duplicative and possibly inconsistent regulation. 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 and (7) 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 when we engage in the storage, transloading and shipment of products owned by others. 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 product margin minus terminal and gasoline station related depreciation expense allocated to cost of sales.

EBITDA

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

Distributable Cash Flow

Distributable cash flow is an important non‑GAAP financial measure for our limited partners since it serves as an indicator of our success in providing a cash return on their investment. Distributable cash flow means our net income plus depreciation and amortization minus maintenance capital expenditures, as well as adjustments to eliminate items approved by the audit committee of the board of directors of our general partner that are extraordinary or non‑ recurring in nature and that would otherwise increase distributable cash flow.

Specifically, this financial measure indicates to investors whether or not we have generated sufficient earnings on a current or historic level that can sustain or support an increase in our quarterly cash distribution. Distributable cash flow is a quantitative standard used by the investment community with respect to publicly traded partnerships. Distributable cash flow should not be considered as an alternative to net income, operating income, cash flow from operations, or any other measure of financial performance presented in accordance with GAAP. In addition, our distributable cash flow may not be comparable to distributable cash flow or similarly titled measures of other companies.

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, transload 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.

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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Key Performance Indicators

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

	Year Ended December 31,
	2015		2014		2013
Net income attributable to Global Partners LP	$	43,563	$	114,709	$	42,615
EBITDA (1)	$	225,689	$	242,279	$	157,394
Distributable cash flow (2)	$	126,855	$	161,224	$	105,254
Wholesale Segment:
Volume (gallons)		3,680,201		4,932,133		5,507,829
Sales
Gasoline and gasoline blendstocks	$	2,714,057	$	7,076,105	$	8,085,225
Crude oil (3)		1,190,560		2,384,018		3,561,428
Other oils and related products (4)		2,006,668		3,436,006		3,559,001
Total	$	5,911,285	$	12,896,129	$	15,205,654
Product margin
Gasoline and gasoline blendstocks	$	66,031	$	71,713	$	43,147
Crude oil (3)		74,182		141,965		92,807
Other oils and related products (4)		67,709		79,376		66,916
Total	$	207,922	$	293,054	$	202,870
Gasoline Distribution and Station Operations Segment(5):
Volume (gallons)		1,515,702		1,029,978		1,047,120
Sales
Gasoline	$	3,289,742	$	3,241,620	$	3,231,925
Station operations (6)		381,194		165,756		146,503
Total	$	3,670,936	$	3,407,376	$	3,378,428
Product margin
Gasoline	$	276,848	$	189,439	$	150,147
Station operations (6)(7)		178,487		93,939		78,833
Total	$	455,335	$	283,378	$	228,980
Commercial Segment:
Volume (gallons)		452,089		393,967		401,482
Sales	$	732,631	$	966,449	$	1,005,526
Product margin	$	29,201	$	29,716	$	28,359
Combined sales and product margin:
Sales	$	10,314,852	$	17,269,954	$	19,589,608
Product margin (8)	$	692,458	$	606,148	$	460,209
Depreciation allocated to cost of sales		(94,789)		(61,361)		(55,653)
Combined gross profit	$	597,669	$	544,787	$	404,556
GDSO portfolio as of December 31, 2015, 2014 and 2013:
Company operated		281		134		114
Commissioned agents		283		217		212
Lessee dealers		280		191		201
Contract dealers		665		394		398
Total GDSO portfolio		1,509		936		925

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	Year Ended December 31,
	2015		2014		2013
Weather conditions:
Normal heating degree days	5,630		5,630		5,630
Actual heating degree days	5,651		5,664		5,521
Variance from normal heating degree days	0.37	%	1	%	(2)	%
Variance from prior period actual heating degree days	(0.23)	%	3	%	16	%

(1) 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.

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

(3) Crude oil consists of our crude oil sales and revenue from our logistics activities.

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

(5) The GDSO segment for 2015 includes the results of the January 2015 acquisition of Warren and the June 2015 acquisition of Capitol (see Note 3 of Notes to Consolidated Financial Statements). As the Warren assets and the Capitol assets were not in place prior to 2015, the above results are not directly comparable to the prior periods. We evaluated the impact of these acquisitions and concluded there were no changes to our reportable segments.

(6) Station operations primarily consist of convenience store sales and rental income.

(7) For the years ended December 31, 2014 and 2013, station operations includes the reclass of loss (gain) on sale and disposition of assets from product margin to operating expenses to conform to our current presentation.

(8) 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.

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,
	2015		2014		2013
Reconciliation of net income to EBITDA:
Net income	$	43,264	$	116,980	$	41,053
Net loss (income) attributable to noncontrolling interest		299		(2,271)		1,562
Net income attributable to Global Partners LP		43,563		114,709		42,615
Depreciation and amortization, excluding the impact of noncontrolling interest		110,670		78,888		70,423
Interest expense, excluding the impact of noncontrolling interest		73,329		47,719		43,537
Income tax (benefit) expense		(1,873)		963		819
EBITDA	$	225,689	$	242,279	$	157,394
Reconciliation of net cash provided by operating activities to EBITDA:
Net cash provided by operating activities	$	62,506	$	344,902	$	255,147
Net changes in operating assets and liabilities and certain non-cash items		96,609		(141,558)		(136,960)
Net cash from operating activities and changes in operating assets and liabilities attributable to noncontrolling interest		(4,882)		(9,747)		(5,149)
Interest expense, excluding the impact of noncontrolling interest		73,329		47,719		43,537
Income tax (benefit) expense		(1,873)		963		819
EBITDA	$	225,689	$	242,279	$	157,394

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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,
	2015		2014		2013
Reconciliation of net income to distributable cash flow:
Net income	$	43,264	$	116,980	$	41,053
Net loss (income) attributable to noncontrolling interest		299		(2,271)		1,562
Net income attributable to Global Partners LP		43,563		114,709		42,615
Depreciation and amortization, excluding the impact of noncontrolling interest		110,670		78,888		70,423
Amortization of deferred financing fees and senior notes discount		6,988		6,186		7,265
Amortization of routine bank refinancing fees		(4,516)		(4,444)		(4,072)
Maintenance capital expenditures, excluding the impact of noncontrolling interest		(29,850)		(34,115)		(10,977)
Distributable cash flow	$	126,855	$	161,224	$	105,254
Reconciliation of net cash provided by operating activities to distributable cash flow:
Net cash provided by operating activities	$	62,506	$	344,902	$	255,147
Net changes in operating assets and liabilities and certain non-cash items		96,609		(141,558)		(136,960)
Net cash from operating activities and changes in operating assets and liabilities attributable to noncontrolling interest		(4,882)		(9,747)		(5,149)
Amortization of deferred financing fees and senior notes discount		6,988		6,186		7,265
Amortization of routine bank refinancing fees		(4,516)		(4,444)		(4,072)
Maintenance capital expenditures, excluding the impact of noncontrolling interest		(29,850)		(34,115)		(10,977)
Distributable cash flow	$	126,855	$	161,224	$	105,254

Results of Operations for Years 2015, 2014 and 2013

Consolidated Sales

Our total sales were $10.3 billion and $17.3 billion for 2015 and 2014, respectively, a decrease of $7.0 billion, or 40%, primarily due to a decrease in prices and to a decline in volume sold. Our aggregate volume of product sold was 5.6 billion gallons and 6.4 billion gallons for 2015 and 2014, respectively, a decrease of 708 million gallons, or 11%. The decrease in volume sold includes a decrease of 1.2 billion gallons in our Wholesale segment, largely in gasoline and gasoline blendstocks, due primarily to the impact of an elective change in supply logistics for a particular gasoline customer in early 2015 and the discontinuation of a small discrete blendstocks distribution activity. The decrease in volume sold was offset by increases of 486 million gallons in our GDSO segment, primarily due to the Warren and Capitol acquisitions, and 59 million gallons in our Commercial segment.

Our total sales were $17.3 billion and $19.6 billion for 2014 and 2013, respectively, a decrease of $2.3 billion, or 12%, primarily due to a decrease in volume sold. Our aggregate volume of product sold was 6.4 billion gallons and 7.0 billion gallons for 2014 and 2013, respectively, a decrease of 600 million gallons, or 9%. The decrease in volume includes decreases of 576 million gallons in our Wholesale segment, 17 million gallons in our GDSO segment and 7 million gallons in our Commercial segment. The decrease in volume sold in our Wholesale segment was due to a shift, primarily by one customer, from crude oil supply sales to fee‑based crude oil delivery logistics and to rail congestion and delays due to severe winter weather conditions in the first quarter and early into the second quarter of 2014. The decline in volume sold was offset by an increase in distillates volume sold due, in part, to colder weather during the first quarter of 2014, when temperatures were 9% colder than normal and 11% colder than the first quarter in 2013.

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Gross Profit

Our gross profit was $597.7 million and $544.8 million for 2015 and 2014, respectively, an increase of $52.9 million, or 10%, due primarily to the Warren acquisition, which significantly contributed to our GDSO segment, and to the Capitol acquisition. The increase in gross profit was primarily offset by tighter crude oil differentials as mid-continent crude oil did not discount sufficiently to make rail transport to the East and West Coasts competitive with imports,as well as fixed costs, including railcar leases and also offset by (i) warmer weather in the fourth quarter of 2015 and a  competitive distillates market during the last three quarters of 2015 that negatively impacted our distillates volume and product margin; (ii) favorable market conditions in gasoline blendstocks, primarily ethanol, in the first quarter and third quarters of 2014 that were not present in the same periods in 2015; and (iii) an increase in depreciation, which is included in cost of sales, primarily related to our 2015 acquisitions of Warren and Capitol.

Our gross profit was $544.8 million and $404.5 million for 2014 and 2013, respectively, an increase of $140.3 million, or 35%. The increase was attributed to (i) improved Wholesale segment margins from an increase in our crude oil activities, including a full year of Basin Transload and Cascade Kelly and improved margins during the third and fourth quarters of 2014, (ii) improved GDSO product margins due to declining gasoline prices during the second half of 2014, (iii) colder weather during the first quarter of 2014 compared to the first quarter of 2013 which improved our product margins for other oils and related products (primarily distillates, residual oil and propane) in our Wholesale segment, (iv) severe winter weather, including extreme cold and snow and the resulting rail congestion, which contributed to very favorable market conditions in gasoline blendstocks, primarily ethanol, (v) favorable market conditions in distillates which improved our Wholesale distillates product margin, and (vi) a $19.3 million negative impact during 2013 from increases of $6.2 million in the liability related to RIN forward commitments and $13.1 million in the mark to market value of the RVO deficiency. In 2014, while we had decreases of $6.2 million in the liability related to RIN forward commitments and $12.8 million in the mark to market value of the RVO deficiency, the resulting favorable impact of $19.0 million was offset by the expense incurred to purchase RINs during the first quarter of 2014 to reduce these liabilities. Our gross profit for 2014 was negatively impacted by (1) a challenging futures market during the second and fourth quarters of 2014, mainly backwardation in the forward product pricing curve in gasoline blendstocks, primarily ethanol, and (2) extreme cold and snow which impacted rail traffic, increased congestion and caused delays which reduced crude oil activities during the first quarter and early into the second quarter of 2014.

Results for Wholesale Segment

Gasoline and Gasoline Blendstocks.  Sales from wholesale gasoline and gasoline blendstocks were $2.7 billion and $7.1 billion for 2015 and 2014, respectively, a decrease of approximately $4.4 billion, or 62%, due to a decrease in volume sold and in gasoline prices. The decrease in volume sold was due primarily to the impact of an elective change in supply logistics for a particular gasoline customer in early 2015 and the discontinuation of a small discrete blendstocks distribution activity. Our gasoline and gasoline blendstocks product margin was $66.0 million and $71.7 million for 2015 and 2014, respectively, a decrease of $5.7 million, or 8%, primarily due to favorable market conditions in gasoline blendstocks, primarily ethanol, during the first and third quarters of 2014 that were not present in 2015.  Our gasoline product margin for 2015 was positively impacted due to favorable market conditions in Wholesale gasoline in the first quarter of 2015.

Sales from wholesale gasoline and gasoline blendstocks were $7.1 billion and $8.1 billion for 2014 and 2013, respectively, a decrease of $1.0 billion, or 13%, due to decreases in volume sold and in gasoline prices during the second half of 2014. Our gasoline and gasoline blendstocks product margin was $71.7 million and $43.1 million for 2014 and 2013, respectively, an increase of $28.6 million, or 66%. The increase was attributed to (i) severe winter weather and the resulting rail congestion which contributed to very favorable market conditions in gasoline blendstocks, primarily ethanol, during the first quarter of 2014 as the availability of railcars for gasoline blendstocks was constrained and certain areas experienced shortages in that product, and (ii) a $19.3 million negative impact during 2013 from increases of $6.2 million in the liability related to RIN forward commitments and $13.1 million in the mark to market value of the RVO deficiency. In 2014, while we had decreases of $6.2 million in the liability related to RIN forward commitments and $12.8 million in the mark to market value of the RVO deficiency, the resulting favorable impact of $19.0 million was offset by the expense incurred to purchase RINs during the first quarter of 2014 to reduce these liabilities. Despite

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the overall increase, our product margin for 2014 was negatively impacted by a challenging futures market during the second and fourth quarters, mainly a backward forward product pricing curve in gasoline blendstocks, primarily ethanol.

Crude Oil.  Crude oil sales and logistics revenues were $1.2 billion and $2.4 billion for 2015 and 2014, respectively, a decrease of $1.2 billion, or 50%, due primarily to a decline in crude oil prices. Our product margin from crude oil was $74.2 million and $142.0 million for 2015 and 2014, respectively, a decrease of $67.8 million, or 48%, primarily due to the result of tighter crude oil differentials as mid-continent crude oil did not discount sufficiently to make rail transport to the East and West Coasts competitive with imports. Also, we had a $5.0 million reserve related to a customer dispute in the first quarter of 2015. Additionally, logistics volume was lower due to declining contractual commitments with one particular customer. Our crude oil product margin was also negatively impacted by fixed costs which include contracted barges, pipeline commitments and railcar leases. The primary fixed cost in 2015 wasour railcar lease expense of $49.0 million for the approximate 2,200 railcars allocated to crude oil, as compared to $35.0 million in 2014. About half of these cars were in storage as of December 31, 2015. The future lease expense for these railcars is estimated at$45.0 million, $45.0 million and $39.0 million in 2016, 2017 and 2018, respectively, with asignificant reductionto approximately $20.0 million in 2019 after which the leases expire. These cars can be used either in crude oil or ethanol service.

Crude oil sales and logistics revenues were $2.4 billion and $3.6 billion for 2014 and 2013, respectively, a decrease of $1.2 billion, or 33%. The decrease was due primarily to a decrease in volume sold due to a shift, primarily by one customer, from crude oil supply sales to fee‑based crude oil delivery logistics and to rail congestion and delays due to severe winter weather conditions in the first quarter and early into the second quarter of 2014. Our product margin from crude oil for was $142.0 million and $92.8 million for 2014 and 2013, respectively, an increase of $49.2 million, or 53%, primarily due to (i) increased crude oil activities at our transloading facilities and improved margins during the third and fourth quarters of 2014, which more than offset the impact of extreme cold and snow during the first quarter and early into the second quarter of 2014 which impacted rail traffic, increased congestion and caused delays which reduced crude oil activity, and (ii) a full year of Basin Transload and Cascade Kelly.

Other Oils and Related Products.  Sales from other oils and related products (primarily distillates, residual oil and propane) were $2.0 billion and $3.4 billion for 2015 and 2014, respectively, a decrease of $1.4 billion, or 41%, primarily due to a decline in prices and, to a lesser extent, a decrease in volume sold.  Our product margin from other oils and related products was $67.7 million and $79.4 million for 2015 and 2014, respectively, a decrease of $11.7 million, or 15%, primarily in distillates due to warmer weather during the fourth quarter of 2015 when temperatures were 24% warmer than normal and 17% warmer than the same period in 2014 and to a competitive distillates market during the last three quarters of 2015. The decrease in margin was partially offset by a  stronger demand for residual oil and a stronger performance in our propane business.

Sales from other oils and related products were $3.4 billion and $3.5 billionfor 2014 and 2013, respectively, a decrease of $0.1 billion, or 3%, due to a decrease in prices. Our product margin from other oils and related products was $79.4 million and $66.9 million for 2014 and 2013, respectively, an increase of $12.5 million, or 19%, primarily in distillates due to colder weather, particularly during the first quarter of 2014 when temperatures were 9% colder than normal and 11% colder than the same period in 2013, and to favorable market conditions.

Results for Gasoline Distribution and Station Operations Segment

Gasoline Distribution.  Sales from gasoline distribution were $3.3 billion and $3.2 billion for 2015 and 2014, respectively, an increase of $48.2 million, or 1.5%, due to an increase in volume sold largely offset by a decline in prices. During 2015, our sales volume benefitted primarily due to the Warren acquisition and, to a lesser extent, the Capitol acquisition. Our product margin from gasoline distribution was $276.8 million and $189.4 million for 2015 and 2014, respectively, an increase of $87.4 million, or 46%, due primarily to the Warren and Capitol acquisitions and to declining gasoline prices during the first quarter of 2015 which improved our product margin for 2015, partially offset by a strong fourth quarter in 2014 when gasoline prices declined sharply which positively impacted our product margin for 2014.  

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Sales from gasoline distribution were flat at $3.2 billion for 2014 and 2013. Our product margin from gasoline distribution was $189.4 million and $150.1 million for 2014 and 2013, respectively, an increase of $39.3 million, or 26%. The increase in our product margin from gasoline distribution for 2014 was due to declining gasoline prices during the third and fourth quarters and to the completion of certain raze and rebuilds and new‑to‑industry gasoline stations and convenience stores. Our product margin for 2014, however, was negatively impacted due to rising gasoline prices during the first six months of 2014.

Station Operations.  Our station operations, which include (i)convenience stores sales at our directly operated stores, (ii)rental income from gasoline stations leased to dealers or from commissioned agents and from cobranding arrangements and (iii) sundries, such as car wash sales, lottery and ATM commissions, collectively generated revenues of $381.2 million and $165.8 million in 2015 and 2014, respectively. Our product margin from station operations was $178.5 million and $93.9 million for 2015 and 2014, respectively. The increases in sales of $215.4 million and product margin of $84.6 million were due primarily to the Warren acquisition and, to a lesser extent, additional rental income as a result of the Capitol acquisition.  

Our station operations collectively generated revenues of $165.8 million and $146.5 million in 2014 and 2013, respectively. Our product margin from station operations was $93.9 million and $78.8 million for 2014 and 2013, respectively. The increases in sales of $19.3 million and product margin of $15.1 million were due primarily to the completion of certain raze and rebuilds and to the addition of 11 convenience store/commission agent and new‑to‑industry gasoline stations and convenience stores during 2014.

Results for Commercial Segment

Our commercial sales were $732.6million, $966.4million and $1.0 billion for 2015, 2014 and 2013, respectively. Our commercial product margin was $29.2 million, $29.7 million and $28.4 million for 2015, 2014 and 2013, respectively. The decrease in sales in 2015 compared to 2014 is primarily due to a decrease in prices.

Selling, General and Administrative Expenses

SG&A expenses were $177.0 million and $154.0 million for 2015 and 2014, respectively, an increase of $23.0 million, or 15%, primarily due to the Warren acquisition. The increase in SG&A expenses was due to increases of (i) $21.7 million in wages and benefits mostly due to an increase in headcount primarily related to Warren, (ii) $3.7 million of acquisition costs related to Warren ($5.4million were recorded in 2015 and $l.7million were recorded in 2014),  (iii) $3.5 million of acquisition costs related to Capitol, (iv) $2.3 million in a restructuring charge associated with the Warren acquisition, (v) $1.1 million in professional fees and (vi) $5.4 million of various other SG&A expenses, including increases in depreciation and insurance expenses, largely due to the Warren and Capitol acquisitions. The increase in SG&A expenses was offset by a decrease of $13.1 million in incentive compensation and $1.6 million in bank fees.

SG&A expenses were $154.0 million and $115.5 million for 2014 and 2013, respectively, an increase of $38.5 million, or 33%. The increase reflects additional costs to support our growing business as well as growth initiatives including our crude oil activities, retail gasoline stations and expansion opportunities. Wages and benefits increased by $10.4 million, primarily due to an increase in headcount, and discretionary incentive compensation, which was accrued for in line with our 2014 performance, and expenses related to our long‑term incentive plan increased by $14.6 million. The increase in SG&A expenses also includes (i) $6.3 million in professional fees, (ii) $3.8 million in depreciation expense, (iii) $1.7 million of costs incurred in connection with the Warren acquisition, and (iv) $6.2 million of other SG&A expenses, including higher rental and overhead expenses related to the office expansion and consolidation at our corporate headquarters. The increase in SG&A expenses was offset by decreases of $2.5 million in bad debt expense and $2.0 million in bank fees.

Operating Expenses

Operating expenses were $290.3 million and $204.1 million for 2015 and 2014, respectively, an increase of $86.2 million, or 42%, due to an increase of $89.0 million associated with our GDSO segment, primarily as a result of

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the Warren and Capitol acquisitions and, to a lesser extent, increases in direct labor, maintenance and repairs and property taxes in our GDSO segment. The increase in operating expenses was offset by decreases of $2.4 million associated with our transloading terminals in North Dakota and $0.4 million in various operating expenses associated with our terminal operations.

Operating expenses were $204.1 million and $185.7 million for 2014 and 2013, respectively, an increase of $18.4 million, or 10%. The increase was primarily due to increases of $13.2 million in costs related to the operations of our retail gasoline stations and new‑to‑industry gasoline stations and convenience stores, including, in part, additional rent, credit card and maintenance expenses associated with our new retail locations and recently renovated sites, $3.4 million in costs associated with our crude oil operations, including a full year of Basin Transload and Cascade Kelly, $2.9 million in operating costs associated with our terminals in Albany, New York and $0.8 million in other operating expenses. The increase in operating expenses was offset by a $1.9 million decrease in expenses at our East Providence, Rhode Island terminal as our lease expired in April 2013, and we elected not to renew.

Amortization Expense

Amortization expense related to our intangible assets was $13.5 million, $18.9 million and $19.2 million for 2015, 2014 and 2013, respectively. The decrease in in amortization expense in 2015 compared to 2014 was due to intangibles that became fully amortized during the second quarter of 2015, partially offset by the intangible assets acquired in the Warren acquisition.

Interest Expense

Interest expense was $73.3 million and $47.7 million for 2015 and 2014, respectively, an increase of $25.6 million, or 54%. The increase was due primarily to increased interest related to the 6.25% Notes and 7.00% Notes (see Note 8 to Notes to Consolidated Financial Statements) and to additional borrowings related to the acquisitions of Warren and, to a lesser extent, Capitol. In addition, our average balance under our working capital revolving credit facility increased to $234.1million from $208.4million in 2014, and our average balance under our revolving credit facility increased to $382.2million in 2015 from $353.2million in 2014. Interest expense also includes $5.6 million for 2015 associated with the financing obligation recognized in connection with the acquisition of Capitol (see Notes 3 and 8 of Notes to Consolidated Financial Statements).

Interest expense for 2014 and 2013 was $47.7 million and $43.5 million, respectively, an increase of $4.2 million, or 10%. The increase was primarily attributed to interest related to our former senior notes  and $1.6 million in expenses associated with the write‑off of certain financing fees in connection with the issuance of our 6.25% notes due 2022.

Income Tax Benefit (Expense)

Income tax benefit (expense) of $1.9 million, ($1.0 million) and ($0.8 million) for 2015, 2014 and 2013, respectively, reflect the operating results of our wholly owned subsidiary, GMG, which is a taxable entity for federal and state income tax purposes.

Net (Loss) Income Attributable to Noncontrolling Interest

In February 2013, we acquired a 60% membership interest in Basin Transload. The net (loss) income attributable to noncontrolling interest of ($0.3 million),  $2.3 million and ($1.6 million) for 2015, 2014 and 2013, respectively, represents Basin Transload’s 40% ownership of the net (loss) income reported.

Liquidity and Capital Resources

Liquidity

Our primary liquidity needs are to fund our working capital requirements, capital expenditures and distributions

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and to service our indebtedness. Our primary sources of liquidity are cash generated from operations, amounts available under our working capital revolving credit facility and equity and debt offerings. Please read “—Credit Agreement” for more information on our working capital revolving credit facility.

Working capital was $272.3 million and $251.5 million at December 31, 2015 and 2014, respectively, an increase of $20.8 million, primarily due to (i) a $52.1 million increase in inventories as we elected to use our storage capacity to hold more inventory due to favorable market conditions; (ii) a $33.0million decrease in trustee taxes and accrued expenses and other current liabilities largely due to timing and to a $13.1million reduction in incentive compensation; and (iii) a reduction in accounts payable and accounts receivable of $152.8 million and $146.4 million, respectively, due to a decline in prices. The net increase more than offset a $98.1 million increase in the current portion of our working capital revolving credit facility, which represents the amount we expect to pay down during the course of the year (see Note 8 of Notes to Consolidated Financial Statements). The increase in inventory contributed to the increase in our working capital revolving credit facility.

Cash Distributions

During 2015, we paid the following cash distributions to our common unitholders and our general partner:

Cash Distribution			Distribution Paid for the
Payment Date	Total Paid		Quarterly Period Ended
February 13, 2015	$	22.4 million	Fourth quarter 2014
May 15, 2015	$	23.3 million	First quarter 2015
August 14, 2015	$	26.3 million	Second quarter 2015
November 13, 2015	$	26.6 million	Third quarter 2015

On January 28, 2016, we announced a reduction in the quarterly distribution for the fourth quarter of 2015 on all outstanding common unitsto $0.4625.  This distribution represented a decrease of 33.7% from the distribution of $0.6975 per unit paid in November 2015 and a decrease of 30.5% from the distribution of $0.6650 per unit paid in February 2015. The reduction in the distribution primarily reflected continuing weakness in the crude oil market.

Contractual Obligations

We have contractual obligations that are required to be settled in cash. The amounts of our contractual obligations at December 31, 2015 were as follows (in thousands):

	Payments due by period
									2020 and
Contractual Obligations	2016		2017		2018		2019		Thereafter		Total
Credit facility obligations (1)	$	116,551	$	219,467	$	219,467	$	—	$	—	$	555,485
Senior notes obligations (2)		44,438		44,438		44,438		44,438		807,092		984,844
Operating lease obligations (3)		166,834		136,730		110,216		65,019		164,158		642,957
Capital lease obligations		176		201		97		—		—		474
Other long-term liabilities (4)		26,548		26,344		24,659		32,597		98,444		208,592
Financing obligation (5)		9,465		9,688		9,917		10,151		107,811		147,032
Total	$	364,012	$	436,868	$	408,794	$	152,205	$	1,177,505	$	2,539,384

(1) Includes principal and interest on our working capital revolving credit facility and our revolving credit facility at December 31,2015 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 the 6.25% Notes and the 7.00% Notes. No principal payments are required prior to maturity.

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(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 barges.See Note13 of Notes to Consolidated Financial Statements for additional information.

(4) Includes amounts related to our 15-year brand fee agreement entered into in 2010 with ExxonMobil and amounts related to our pipeline connection agreements and our natural gas transportation and reservation agreements (see Note13 of Notes to Consolidated Financial Statements for additional information on these agreements). Other long-term liabilities also includes pension and deferred compensation obligations.

(5) Includes lease rental payments in connection with the acquisition of Capitol related to properties previously sold by Capitol within two sale-leaseback transactions that did not meet the criteria for sale accounting and will be classified as interest expense on the financing obligation and the pay-down of the financing obligation. See Note 8 of Notes to Consolidated Financial Statement for additional information.

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 also 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 $30.0 million, $34.1 million and $11.0 million in maintenance capital expenditures for the years ended December 31, 2015, 2014 and 2013, respectively, which are included in capital expenditures in the accompanying consolidated statements of cash flows and largely consisted of investments in our gasoline stations and in information technology and equipment upgrades at various terminals.  Specifically for 2015, approximately $20.8 million out of the $30.0 million was related to our investments in our gasoline stations. The increase in maintenance capital expenditures in 2014 compared to 2013 was primarily due to additional expenditures related to our gasoline stations, office expansion and consolidation costs and investments in information technology. Repair and maintenance expenses associated with existing assets that are minor in nature and do not extend the useful life of existing assets are charged to operating expenses as incurred.

Expansion capital expenditures include expenditures to acquire assets to grow our business or expand our existing facilities, such as projects that increase our operating capacity or revenues by increasing, for example, rail capacity, dock capacity and tankage, diversifying product availability, raze and rebuilds, new‑to‑industry gasoline stations and convenience stores, storage flexibility at various terminals and by 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 $496.1 million, $61.0 million and $146.2 million in expansion capital expenditures for the years ended December 31, 2015, 2014 and 2013, respectively, which are included in capital expenditures in the accompanying consolidated statements of cash flows.

In 2015, the $496.1 million in expansion capital expenditures included approximately $433.2 million in property and equipment associated with the acquisitions of Warren, the Revere Terminal and Capitol. In addition, we had $62.9 million in expansion capital expenditures which consists of (i) $36.8 million in rebuilds, expansion and improvements at retail gasoline stations and new-to-industry sites, (ii) $15.0 million in costs associated with our crude oil activities, including, tank construction projects, dock and rail expansion and improvement costs and equipment upgrades and (iii) $11.1 million in other expansion capital expenditures including, in part, investments in information technology and computer and equipment upgrades at various terminals.

In 2014, the $61.0 million in expansion capital expenditures included approximately $24.1 million in costs associated with our crude oil activities, $20.4 million in new site development, rebuilds, expansion and improvements at retail gasoline stations, $5.2 million in costs associated with our propane storage and distribution facility in Albany, New York and $11.3 million in other expansion capital expenditures including, office consolidation costs, investments in

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information technology and computer upgrades at various terminals, and additional equipment costs related to our compressed natural gas operations. The $24.1 million in costs associated with our crude oil activities include, in part, tank construction projects, rail expansion and improvement costs and the purchase of land for future rail expansion.

In 2013, the $146.2 million in 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 $15.0 million, $24.1 million and $23.6 million for 2015, 2014 and 2013, respectively, 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 statements of cash flows as we concluded that we control the entity based on an evaluation of the outstanding voting interests.

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

Cash Flow

The following table summarizes cash flow activity for the years ended December 31 (in thousands):

	2015		2014		2013
Net cash provided by operating activities	$	62,506	$	344,902	$	255,147
Net cash used in investing activities	$	(649,764)	$	(91,093)	$	(243,207)
Net cash provided by (used in) financing activities	$	583,136	$	(257,788)	$	(8,700)

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 product prices, working capital requirements and general market conditions.

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Net cash provided by operating activities was $62.5 million for 2015 compared to $344.9 million for 2014, for a year‑over‑year decrease in cash provided by operating activities of $282.4 million. Net cash provided by operating activities was $344.9 million for 2014 compared to $255.1 million for 2013, for a year‑over‑year increase in cash provided by operating activities of $89.8 million. The primary drivers of the changes for the years ended December 31 include the following (in thousands):

	2015		2014		Change		2014		2013		Change
Decrease (increase) in accounts receivable	$	154,716	$	226,962	$	(72,246)	$	226,962	$	8,524	$	218,438
(Increase) decrease in inventories	$	(32,648)	$	235,993	$	(268,641)	$	235,993	$	61,992	$	174,001
(Decrease) increase in accounts payable	$	(172,318)	$	(324,500)	$	152,182	$	(324,500)	$	18,667	$	(343,167)
(Increase) decrease in derivatives	$	(8,869)	$	(17,509)	$	8,640	$	(17,509)		5,778	$	(23,287)

In 2015, the decreases in accounts payable and accounts receivable were primarily due to declining prices during the year. In addition, due to favorable market conditions, we elected to use our storage to carry increased levels of inventory. The decrease in net cash provided by operating activities was also due to the year‑over‑year decrease in net income of $73.7 million, of which $29.5 million relates to increased depreciation and amortization, primarily from the Warren and Capitol acquisitions.

In 2014, the decreases in accounts payable, inventories and accounts receivable were primarily due to declining prices. The increase in net cash provided by operating activities was largely due to the year‑over‑year increase in net income of $75.9 million. In addition, through the use of regulated exchanges and other over‑the‑counter derivatives, we maintain a position that is substantially hedged with respect to our inventories and forward commodity purchases and sales. In 2014, the contracts supporting our derivative hedge program required margin payments.

In 2013, 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, in 2013 the contracts supporting our derivative hedge program provided funds.

Net cash used in investing activities was $649.7 million for 2015 and included $381.8 million, $155.7 million and $23.7 million in cash used to fund the acquisitions of Warren, Capitol and the Revere Terminal, respectively, $62.9 million in expansion capital expenditures and $30.0 million in maintenance capital expenditures, offset by $4.3 million in proceeds from the sale of property and equipment.

Net cash used in investing activities was $91.1 million for 2014 and included $61.0 million in expansion capital expenditures and $34.1 million in maintenance capital expenditures, offset by $4.0 million in proceeds from the sale of property and equipment.

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.

Please read “—Capital Expenditures” for a discussion of our expansion capital expenditures for the years ended December 31, 2015, 2014 and 2013.

Net cash provided by financing activities was $583.1 million for 2015 and included $295.3 million in net proceeds from the issuance of our 7.00% Notes, $148.1 million in net borrowings from our working capital revolving credit facility, in part to fund an increase in stored inventory due to favorable market conditions, $135.2 million in net borrowings from our revolving credit facility to fund the acquisitions of Warren, the Revere Terminal and Capitol, $109.3 million in net proceeds from our June 2015 issuance of common units and $2.6 million in capital contributions from our noncontrolling interest at Basin Transload. Net cash provided by financing activities was offset by $97.5 million in cash distributions to our common unitholders and our general partner, $5.3 million in distributions to

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our noncontrolling interest at Basin Transload, $3.9 million in the repurchase of common units pursuant to our repurchase program for future satisfaction of our LTIP obligations and $0.7 million in net payments on our line of credit related to Basin Transload.

Net cash used in financing activities was $257.8 million for 2014 and included $300.9 million in net payments on our working capital revolving credit facility, $227.0 million in net payments on our revolving credit facility in connection with the issuance of our 6.25% notes due 2022, $73.8 million in cash distributions to our common unitholders and our general partner, $40.2 million in payments related to the exchange of our former senior notes in connection with the issuance of our 6.25% notes due 2022, $9.2 million distributions to our noncontrolling interest at Basin Transload, $8.6 million in the repurchase of common units pursuant to our repurchase program for future satisfaction of our LTIP obligations and $3.0 million in net payments on our line of credit related to Basin Transload. Net cash used in financing activities was offset by $258.9 million in net proceeds from the issuance of our 6.25% notes due 2022, $137.8 million in proceeds from our December 2014 public offering and $8.2 million in capital contributions from our noncontrolling interest at Basin Transload.

Net cash used in financing activities was $8.7 million for 2013 and included $97.5 million in net 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 LTIP 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 net proceeds from the issuances of our senior notes, $12.7 million in net 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.

Credit Agreement

As of December 31, 2015, certain subsidiaries of ours, as borrowers, and we and certain of our subsidiaries, as guarantors, had a $1.775 billion senior secured credit facility. On February 24, 2016, we and certain of our subsidiaries entered into the fifth amendment to our credit agreement. This amendment reflects our voluntary election to reduce the maximum aggregate amount available under our credit agreement to $1.475 billion (see “—Amendment to Credit Agreement” below).

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, 2015, 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 $775.0 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. 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.

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

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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 $1.775 billion.

Availability under the working capital revolving credit facility is subject to a borrowing base which is redetermined from time to time 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.

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). 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).

The average balance under our working capital revolving credit facility was $234.1million and $208.4million for the years ended December 31, 2015 and 2014, respectively, and the average balance under our revolving credit facility was $382.2million and $353.2million for the years ended December 31, 2015 and 2014, respectively.  The average interest rates for the credit agreement were 3.6%, 3.7% and 4.2% for the years ended December 31, 2015, 2014 and 2013, 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, 2015, we had total borrowings outstanding under the credit agreement of $517.1 million, including $269.0 million outstanding on the revolving credit facility. In addition, we had outstanding letters of credit of $63.7 million. Subject to borrowing base limitations, the total remaining availability for borrowings and letters of credit was $1.2 billion and $1.4 billion at December 31, 2015 and 2014, respectively.

Our obligations under the credit agreement are secured by substantially all of our assets and the assets of our wholly owned subsidiaries, and the credit agreement is guaranteed by us and our subsidiaries with the exception of Basin Transload.

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, 2015. 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).

Amendment to Credit Agreement

On February 24, 2016, we and certain of our subsidiaries entered into the fifth amendment to our credit agreement (the “Fifth Amendment”). The Fifth Amendment includes certain modifications to our credit agreement to (i) amend the definition of “Total Combined Leverage Ratio” to permit for an increased maximum ratio of 5.50:1.00 through the first quarter of 2017 and 5.00:1.00 thereafter, (ii) amend the definition of “Applicable Revolver Rate” to align the pricing levels with the amended Total Combined Leverage Ratio maximum thresholds, (iii) increase the

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permitted level of asset Dispositions (as it is defined in the credit agreement) from $100.0 million to $150.0 million, and (iv) incorporate acknowledgement of and consent to the applicability of European Union Bank Recovery and Resolution Directive bail-in legislation. 

Unrelated to the foregoing modifications, the Fifth Amendment also reflects our voluntary election to reduce our working capital revolving credit facility from $1.0 billion to $900.0 million and our revolving credit facility from $775.0 million to $575.0 million, for a total available commitment of $1.475 billion.

6.25% Senior Notes

On June 19, 2014, we and GLP Finance Corp. (“GLP Finance” and, together with us, the “Issuers”) entered into a Purchase Agreement (the “Purchase Agreement”) with the Initial Purchasers (as defined therein) (the “Initial Purchasers”) pursuant to which the Issuers agreed to sell $375.0 million aggregate principal amount of the Issuers’ 6.25% senior notes due 2022 (the “6.25% Notes”) to the Initial Purchasers in a private placement exempt from the registration requirements under the Securities Act of 1933, as amended (the “Securities Act”). The 6.25% Notes were resold by the Initial Purchasers to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to persons outside the United States pursuant to Regulation S under the Securities Act.

The Purchase Agreement contained customary representations and warranties of the parties and indemnification and contribution provisions under which the Issuers and the subsidiary guarantors, on one hand, and the Initial Purchasers, on the other, agreed to indemnify each other against certain liabilities, including liabilities under the Securities Act. In addition, the Purchase Agreement required the execution of a registration rights agreement, described below, relating to the 6.25% Notes.Closing of the offering occurred on June 24, 2014.

Indenture

In connection with the private placement of the 6.25% Notes on June 24, 2014, the Issuers and the subsidiary guarantors and Deutsche Bank Trust Company Americas, as trustee, entered into an indenture (the “Indenture”).

The 6.25% Notes mature on July 15, 2022 with interest accruing at a rate of 6.25% per annum and payable semi‑annually in arrears on January 15 and July 15 of each year, commencing January 15, 2015. The 6.25% Notes are guaranteed on a joint and several senior unsecured basis by each of the Issuers and the subsidiary guarantors to the extent set forth in the Indenture. Upon a continuing event of default, the trustee or the holders of at least 25% in principal amount of the 6.25% Notes may declare the 6.25% Notes immediately due and payable, except that an event of default resulting from entry into a bankruptcy, insolvency or reorganization with respect to us, any restricted subsidiary of ours that is a significant subsidiary or any group of our restricted subsidiaries that, taken together, would constitute a significant subsidiary of ours, will automatically cause the 6.25% Notes to become due and payable.

The Issuers have the option to redeem up to 35% of the 6.25% Notes prior to July 15, 2017 at a redemption price (expressed as a percentage of principal amount) of 106.25% plus accrued and unpaid interest, if any. The Issuers have the option to redeem the 6.25% Notes, in whole or in part, at any time on or after July 15, 2017, at the redemption prices of 104.688% for the twelve‑month period beginning on July 15, 2017, 103.125% for the twelve‑month period beginning July 15, 2018, 101.563% for the twelve‑month period beginning July 15, 2019, and 100.0% beginning on July 15, 2020 and at any time thereafter, together with any accrued and unpaid interest to the date of redemption. In addition, before July 15, 2017, the Issuers may redeem all or any part of the 6.25% Notes at a redemption price equal to the sum of the principal amount thereof, plus a make whole premium at the redemption date, plus accrued and unpaid interest, if any, to the redemption date. The holders of the notes may require the Issuers to repurchase the 6.25% Notes following certain asset sales or a Change of Control (as defined in the Indenture) at the prices and on the terms specified in the Indenture.

The Indenture contains covenants that will limit our ability to, among other things, incur additional indebtedness and issue preferred securities, make certain dividends and distributions, make certain investments and other restricted payments, restrict distributions by our subsidiaries, create liens, enter into sale‑leaseback transactions, sell assets or merge with other entities. Events of default under the Indenture include (i) a default in payment of principal of,

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or interest or premium, if any, on, the 6.25% Notes, (ii) breach of our covenants under the Indenture, (iii) certain events of bankruptcy and insolvency, (iv) any payment default or acceleration of indebtedness of ours or certain subsidiaries if the total amount of such indebtedness unpaid or accelerated exceeds $15.0 million and (v) failure to pay within 60 days uninsured final judgments exceeding $15.0 million.

Registration Rights Agreement

On June 24, 2014, the Issuers and the subsidiary guarantors entered into a registration rights agreement (the “Registration Rights Agreement”) with the Initial Purchasers in connection with the Issuers’ private placement of the 6.25% Notes. Under the Registration Rights Agreement, the Issuers and the subsidiary guarantors agreed to file and use commercially reasonable efforts to cause to become effective a registration statement relating to an offer to exchange the 6.25% Notes for an issue of SEC‑registered notes with terms identical to the 6.25% Notes (except that the exchange notes are not subject to restrictions on transfer or to any increase in annual interest rate for failure to comply with the Registration Rights Agreement) that are registered under the Securities Act so as to permit the exchange offer to be consummated by the 360th day after June 24, 2014. The exchange offer was completed on April 21, 2015, and 100% of the 6.25% Notes were exchanged for SEC-registered notes.

7.00% Senior Notes

On June 1, 2015, the Issuers entered into a Purchase Agreement (the “7.00% Notes Purchase Agreement”) with the Initial Purchasers (as defined therein) (the “7.00% Notes Initial Purchasers”) pursuant to which the Issuers agreed to sell $300.0million aggregate principal amount of the Issuers’ 7.00% senior notes due 2023 (the “7.00% Notes”) to the 7.00% Notes Initial Purchasers in a private placement exempt from the registration requirements under the Securities Act. The 7.00% Notes were resold by the 7.00% Notes Initial Purchasers to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to persons outside the United States pursuant to Regulation S under the Securities Act.

The 7.00% Notes Purchase Agreement contained customary representations and warranties of the parties and indemnification and contribution provisions under which the Issuers and the subsidiary guarantors, on one hand, and the 7.00% Notes Initial Purchasers, on the other, agreed to indemnify each other against certain liabilities, including liabilities under the Securities Act. In addition, the 7.00% Notes Purchase Agreement required the execution of a registration rights agreement, described below, relating to the 7.00% Notes. Closing of the offering occurred on June 4, 2015.

Indenture

In connection with the private placement of the 7.00% Notes on June 4, 2015 the Issuers and the subsidiary guarantors and Deutsche Bank Trust Company Americas, as trustee, entered into an indenture (the “7.00% Notes Indenture”).

The 7.00% Notes will mature on June 15, 2023 with interest accruing at a rate of 7.00% per annum and payable semi-annually in arrears on June 15 and December 15 of each year, commencing December 15, 2015. The 7.00% Notes are guaranteed on a joint and several senior unsecured basis by each of the Issuers and the subsidiary guarantors to the extent set forth in the 7.00% Notes Indenture. Upon a continuing event of default, the trustee or the holders of at least 25% in principal amount of the 7.00% Notes may declare the 7.00% Notes immediately due and payable, except that an event of default resulting from entry into a bankruptcy, insolvency or reorganization with respect to us, any restricted subsidiary of ours that is a significant subsidiary or any group of our restricted subsidiaries that, taken together, would constitute a significant subsidiary of ours, will automatically cause the 7.00% Notes to become due and payable.

The Issuers will have the option to redeem up to 35% of the 7.00% Notes prior to June 15, 2018 at a redemption price (expressed as a percentage of principal amount) of 107.00% plus accrued and unpaid interest, if any. The Issuers have the option to redeem the 7.00% Notes, in whole or in part, at any time on or after June 15, 2018, at the redemption prices of 105.250% for the twelve-month period beginning June 15, 2018, 103.500% for the twelve-month period beginning June 15, 2019, 101.750% for the twelve-month period beginning June 15, 2020, and 100.0% beginning

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June 15, 2021 and at any time thereafter, together with any accrued and unpaid interest to the date of redemption. In addition, before June 15, 2018, the Issuers may redeem all or any part of the 7.00% Notes at a redemption price equal to the sum of the principal amount thereof, plus a make whole premium, plus accrued and unpaid interest, if any, to the redemption date. The holders of the 7.00% Notes may require the Issuers to repurchase the 7.00% Notes following certain asset sales or a Change of Control (as defined in the 7.00% Notes Indenture) at the prices and on the terms specified in the 7.00% Notes Indenture.

The 7.00% Notes Indenture contains covenants that will limit our ability to, among other things, incur additional indebtedness and issue preferred securities, make certain dividends and distributions, make certain investments and other restricted payments, restrict distributions by our subsidiaries, create liens, enter into sale-leaseback transactions, sell assets or merge with other entities. Events of default under the 7.00% Notes Indenture include (i) a default in payment of principal of, or interest or premium, if any, on, the 7.00% Notes, (ii) breach of our covenants under the 7.00% Notes Indenture, (iii) certain events of bankruptcy and insolvency, (iv) any payment default or acceleration of indebtedness of ours or certain subsidiaries if the total amount of such indebtedness unpaid or accelerated exceeds $50.0 million and (v) failure to pay within 60 days uninsured final judgments exceeding $50.0 million.

Registration Rights Agreement

On June 4, 2015, the Issuers and the subsidiary guarantors entered into a registration rights agreement (the “7.00% Notes Registration Rights Agreement”) with the 7.00% Notes Initial Purchasers in connection with the Issuers’ private placement of the 7.00% Notes. Under the 7.00% Notes Registration Rights Agreement, the Issuers and the subsidiary guarantors agreed to file and use commercially reasonable efforts to cause to become effective a registration statement relating to an offer to exchange the 7.00% Notes for an issue of SEC-registered notes with terms identical to the 7.00% Notes (except that the exchange notes are not subject to restrictions on transfer or to any increase in annual interest rate for failure to comply with the 7.00% Notes Registration Rights Agreement) that are registered under the Securities Act so as to permit the exchange offer to be consummated by the 420th day after June 4, 2015. The exchange offer was completed on October 22, 2015, and 100% of the 7.00% Notes were exchanged for SEC-registered notes.

Line of Credit

On December 9, 2013, Basin Transload entered into a line of credit facility which allows for borrowings by Basin Transload of up to $10.0 million on a revolving basis. The facility had an outstanding balance of $0 and $0.7 million at December 31, 2015 and 2014, respectively. The facility, which expired on February 9, 2016, was secured by substantially all of the assets of Basin Transload and was not guaranteed by us or any of our wholly owned subsidiaries.

Financing Obligation

In connection with the Capitol acquisition on June1, 2015 (see Note 3 of Notes to Consolidated Financial Statements), we assumed a financing obligation of $89.6million associated with two sale-leaseback transactions by Capitol for 53 leased sites that did not meet the criteria for sale accounting. During the term of these leases, which expire in May 2028 and September 2029, in lieu of recognizing lease expense for the lease rental payments, we incur interest expense associated with the financing obligation. Interest expense of approximately $5.6million was recorded for the year ended December 31, 2015 and included in interest expense in the accompanying statement of operations. The financing obligation will amortize through expiration of the lease based upon the lease rental payments which were $5.4 million for the year ended December 31, 2015. The financing obligation balance outstanding at December 31, 2015 was $89.8 million.

Deferred Financing Fees

We incur bank fees related to our credit agreement and other financing arrangements. These deferred financing fees are amortized over the life of the credit agreement or other financing arrangements. We capitalized deferred financing fees of $19.0 million and $24.0 millionat December 31, 2015and 2014, respectively.

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Unamortized fees related to the credit agreement are included in other current assets and other long-term assetsand amounted to $11.2 million and $16.0 million at December 31, 2015 and 2014, respectively. Unamortized fees related to the senior notes are presented as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts,  and amounted to $7.8 million and $8.0 million at December 31, 2015 and 2014, respectively.  As of December31, 2015, we adopted ASU2015-03, “Interest-Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs,” See Note2 of Notes to Consolidation Financial Statements.

Amortization expense of approximately $5.9million, $5.6 million and $6.9 million for the years ended December 31, 2015, 2014 and 2013, respectively, are included in interest expense in the accompanying consolidated statements of operations.

Off‑Balance Sheet Arrangements

We have no off‑balance sheet arrangements.

Impact of Inflation

Inflation 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, 2015, 2014 and 2013.

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.

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

We hedge substantially all of our petroleum and ethanol inventory using a variety of instruments, primarily exchanged‑traded futures contracts. These futures contracts are entered into when inventory is purchased and are either designated as fair value hedges against the inventory on a specific barrel basis for inventories qualifying for fair value hedge accounting or not designated and maintained as economic hedges against certain inventory of ours a specific barrel basis. Changes in fair value of these futures contracts, as well as the offsetting change in fair value on the hedged inventory, is recognized in earnings as an increase or decrease in cost of sales. All hedged inventory designated in a fair value hedge relationship is valued using the lower of cost, as determined by specific identification, or market, as determined at the product level. All petroleum and ethanol inventory not designated in a fair value hedging relationship is carried at the lower of historical cost, on a first‑in, first‑out basis, or market.

Convenience store inventory and RIN inventory are carried at the lower of historical cost or market.

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In addition to our own inventory, we have exchange agreements for petroleum products and ethanol 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 had a throughput agreement with GPC, one of our affiliates, with respect to its terminal in Revere, Massachusetts. This agreement was accounted for as an operating lease in 2014 and 2013. On January 14, 2015, we acquired the Revere Terminal from GPC. 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 our Oregon facility. We also have terminal and throughput lease arrangements with various unrelated oil terminals and third parties, certain of which arrangements have minimum usage requirements. 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.

We have future commitments, principally for office space and computer equipment, under the terms of operating lease arrangements. We also lease railcars and barges through various lease arrangements with various expiration dates. We have rental income from gasoline stations and cobranding arrangements 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 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 when we engage 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. 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.

Product 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 to be recorded as a nonmonetary adjustment of inventory costs.

We collect trustee taxes, which consist of various pass through taxes collected on behalf of taxing authorities, and remit 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

We principally use derivative instruments, which include regulated exchange‑ traded futures and options contracts (collectively, “exchange‑traded derivatives”) and physical and financial forwards and over‑the counter (“OTC”) swaps (collectively, “OTC derivatives”), to reduce our exposure to unfavorable changes in commodity market prices and interest rates. We use these exchange‑traded and OTC derivatives to hedge commodity price risk associated

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with our inventory and undelivered forward commodity purchases and sales (“physical forward contracts”) and use interest rate swap instruments to reduce our exposure to fluctuations in interest rates associated with our credit facilities. We account for derivative transactions in accordance with ASC815, “Derivatives and Hedging,” and recognize derivatives instruments as either assets or liabilities in the consolidated balance sheet and measure those instruments at fair value. The changes in fair value of the derivative transactions are presented in earnings, unless specific hedge accounting criteria are met.

The fair value of exchange‑traded derivative transactions reflects amounts that would be received from or paid to our brokers upon liquidation of these contracts. The fair value of these exchange‑traded derivative transactions are presented on a net basis, offset by the cash balances on deposit with our brokers, presented as brokerage margin deposits in the consolidated balance sheets. The fair value of OTC derivative transactions reflects amounts that would be received from or paid to a third party upon liquidation of these contracts under current market conditions. The fair value of these OTC derivative transactions is presented on a gross basis as derivative assets or derivative liabilities in the consolidated balance sheets, unless a legal right of offset exists. The presentation of the change in fair value of our exchange‑ traded derivatives and OTC derivative transactions depends on the intended use of the derivative and the resulting designation.

Derivatives Accounted for as Hedges—We utilize fair value hedges and cash flow hedges to hedge commodity price risk and interest rate risk.

Fair Value Hedges

Derivatives designated as fair value hedges are used to hedge price risk in commodity inventories and principally include exchange‑traded futures contracts that are entered into in the ordinary course of business. For a derivative instrument designated as a fair value hedge, the gain or loss is recognized in earnings in the period of change together with the offsetting change in fair value on the hedged item of the risk being hedged. Gains and losses related to fair value hedges are recognized in the consolidated statement of operations through cost of sales. These futures contracts are settled on a daily basis by us through brokerage margin accounts.

Cash Flow Hedges

Derivatives designated as cash flow hedges are used to hedge interest rate risk from fluctuations in interest rates and may include various interest rate derivative instruments entered into with major financial institutions. For a derivative instrument being designated as a cash flow hedge, the effective portion of the derivative gain or loss is initially reported as a component of other comprehensive income (loss) and subsequently reclassified into the consolidated statement of operations through interest expense in the same period that the hedged exposure affects earnings. The ineffective portion is recognized in the consolidated statement of operations immediately.

Derivatives Not Accounted for as Hedges—We utilize petroleum and ethanol commodity contracts, natural gas commodity contracts and foreign currency derivatives to hedge price and currency risk in certain commodity inventories and physical forward contracts.

Petroleum and Ethanol Commodity Contracts

We use exchange‑traded derivative contracts to hedge price risk in certain commodity inventories which do not qualify for fair value hedge accounting or are not designated by us as fair value hedges. Additionally, we use exchange‑ traded derivative contracts, and occasionally financial forward and OTC swap agreements, to hedge commodity price exposure associated with our physical forward contracts which are not designated by us as cash flow hedges. These physical forward contracts, to the extent they meet the definition of a derivative, are considered OTC physical forwards and are reflected as derivative assets or derivative liabilities in the consolidated balance sheet. The related exchange‑ traded derivative contracts (and financial forward and OTC swaps, if applicable) are also reflected as brokerage margin deposits (and derivative assets or derivative liabilities, if applicable) in the consolidated balance sheet, thereby creating an economic hedge. Changes in fair value of these derivative instruments are recognized in the consolidated statement of operations through cost of sales. These exchange traded derivatives are settled on a daily basis by us through brokerage margin accounts.

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While we seek to maintain a position that is substantially balanced within our commodity product purchase and sale activities, we may experience net unbalanced positions for short periods of time as a result of variances in daily purchases and 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, we are aided by maintaining a constant presence in the marketplace. We also engage in a controlled trading program for up to an aggregate of 250,000 barrels of commodity products at any one point in time. Changes in fair value of these derivative instruments are recognized in the consolidated statement of operations through cost of sales.

Natural Gas Commodity Contracts

We use physical forward purchase contracts to hedge price risk associated with the marketing and selling of natural gas to third‑party users. These physical forward purchase commitments for natural gas are typically executed when we enter into physical forward sale commitments of product for physical delivery. These physical forward contracts, to the extent they meet the definition of a derivative, are reflected as derivative assets and derivative liabilities in the consolidated balance sheet. Changes in fair value of the forward purchase and sale commitments are recognized in the consolidated statement of operations through cost of sales.

Foreign Currency Contracts

We use forward foreign currency contracts to hedge certain foreign denominated (Canadian) commodity product purchases. These forward foreign currency contracts are not designated by us as hedges and are reflected as prepaid expenses and other current assets or accrued expenses and other current liabilities in the consolidated balance sheets. Changes in fair values of these forward foreign currency contracts are reflected in cost of sales.

Margin Deposits

All of our exchange‑traded derivative contracts (designated and not designated) are transacted through clearing brokers. We deposit initial margin with the clearing brokers, along with variation margin, which is paid or received on a daily basis, based upon the changes in fair value of open futures contracts and settlement of closed futures contracts. Cash balances on deposit with clearing brokers and open equity are presented on a net basis within brokerage margin deposits in the consolidated balance sheets.

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.

No material impairment charges were required in 2015, 2014 and 2013. However, at December 31, 2015, we had a $39.4 million remaining net book value of long‑lived assets used at our crude oil transloading terminals in North Dakota. The long‑term recoverability of these assets might be adversely impacted by any prolonged decline in crude oil commodity prices or crude oil differentials. Over the long‑term, if these market conditions remain, this may become an indicator of the potential impairment of these North Dakota assets in the future. We will monitor the pricing environment and the related impact this may have on the North Dakota operating and cash flows and whether this would constitute an impairment indicator.

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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 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 process of testing goodwill for impairment involves numerous judgments, assumptions and estimates made by management which inherently reflect a high degree of uncertainty. 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 will then complete a two-step quantitative assessment. In the quantitative assessment, the fair value of each reporting unit is determined and compared to the book value of the reporting unit. If the fair value of the reporting unit is less than the book value, including goodwill, then the recorded goodwill is impaired to its implied fair value with a charge to operations. We calculate the fair value of each reporting unit using a combination of discounted cash flows and market comparables.

Key assumptions included in the development of the discounted cash flow value for each reporting unit include:

Future commodity volumes and margins.  The discounted cash flows are based on a five-year forecast with an estimate of terminal value. In general, our reporting units’ fair values are most sensitive to volume and gross margin assumptions. In particular, our Wholesale segment’s cash flows are impacted by the crude oil market, given our 2013 investment in transloading terminals in North Dakota and Oregon. The significant decline in the price of crude oil and tight crude oil differentials negatively impacted our fiscal 2015 results. We expect low crude oil prices and tight differentials to continue for a period of time, which will negatively impact our 2016 performance with recovery expected in 2017. As a result of these market conditions, there is increased uncertainty and sensitivity relating to our future cash flow projections within our crude oil business on which the Wholesale reporting unit’s goodwill impairment analysis relies. If market conditions, and therefore our performance, are worse than our projections, we may record impairment charges in the future. Actual results may not be consistent with these judgments, assumptions and estimates, and goodwill impairment charges may be required in future periods. This could have an adverse impact on our financial position and results of operations.

Discount rate commensurate with the risks involved.  We apply a discount rate to our expected cash flows based on a variety of factors, including market and economic conditions, operational risk, regulatory risk and political risk. A higher discount rate decreases the net present value of cash flows.

Future capital requirements.  Our estimates of future capital requirements are based upon a combination of authorized spending and internal forecasts.

On October 1, 2015, we completed our quantitative assessments for both the Wholesale and GDSO reporting units, and no impairment indicator was identified for either reporting unit. The declining crude oil prices, changes in certain market conditions, and decline in our stock price, collectively caused us to reassess our goodwill for impairment as of December31, 2015. Based on the results of this assessment, we concluded that step-two of the quantitative assessment was not necessary and no impairment was required. 

The fair values of our reporting units are based on underlying assumptions that represent our best estimates. Many of the factors used in assessing fair value are outside of the control of management. A further sustained decline in commodity prices may cause us to reassess our long-lived assets and goodwill for impairment, and could result in future non-cash impairment charges as a result of such impairment assessments. If we are required to perform step-two in the future for the Wholesale reporting unit, up to $121.7million of goodwill assigned to this reporting unit could be written off in the period of such impairment assessment.

During 2014, we completed step-one quantitative assessments for both the Wholesale and GDSO reporting units and no impairment was identified for either reporting unit. Due to declining oil prices and other market indicators at December 31, 2014, we updated the assessment of the recovery of goodwill through December 31, 2014 and concluded

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there was no impairment. During 2013, we completed a qualitative assessment for the GDSO reporting unit and no impairment was required. During 2013, a quantitative assessment was completed for the Wholesale reporting unit, and no impairment was required.

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 related contingencies are resolved, generally upon cash receipt.

We are subject to other contingencies, including legal proceedings and claims arising out of our business 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 certain circumstances in which no range of potential exposure may be reasonably estimated. Please read Item 3, “Legal Proceedings.”

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, 2015, we had total borrowings outstanding under our credit agreement of $517.0 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 $5.2 million annually, assuming, however, that our indebtedness remained constant throughout the year.

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In October 2009, we executed an interest rate swap with a major financial institution. The swap, which became effective on May 16, 2011 and expires on May 16, 2016, is used to hedge the variability in interest payments due to changes in the one‑month LIBOR swap curve with respect to $100.0 million of one‑month LIBOR‑based borrowings on the credit facility at a fixed rate of 3.93%.

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

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

In the aggregate, these hedging instruments historically have hedged the variability in interest payments due to changes in the one‑month LIBOR swap curve or rate with respect to $300.0 million of one‑month LIBOR‑based borrowings on the credit facility.

In June 2014 and as a result of the issuance of our $375.0 million aggregate principal amount of the 6.25% Notes (see Note 8 of Notes to Consolidated Financial Statements included elsewhere in this report), we determined that maintaining an excess of $300.0 million in principal of outstanding floating‑rate debt was no longer probable. Therefore, we elected to de‑designate our interest rate cap and discontinued the related hedge accounting for this instrument. Accordingly, at December 31, 2015, we had in place two interest rate swap agreements which are hedging $200.0 million of variable rate debt, both of which continue to be accounted for as cash flow hedges. The interest rate cap is not currently in a hedging relationship. Accordingly, all changes in the fair value of this instrument are recorded in earnings.

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

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 exchange‑traded 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 commodity product purchase and sales activities, we may experience net unbalanced positions for short periods of time as a result of variances in daily purchases and 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, we are aided by maintaining a constant presence in the marketplace. We also engage in a controlled trading program for up to an aggregate of 250,000 barrels of commodity products at any one point in time. Changes in the fair value of these derivative instruments are recognized in the consolidated statements of operations through cost of sales. In addition, because a portion of our crude oil business may be conducted in Canadian dollars, we may use foreign currency derivatives to minimize the risks of unfavorable exchange rates. These instruments may 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

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currency risk. These foreign currency derivatives are generally short‑term in nature and not designated for hedge accounting.

We utilize exchange‑traded 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 exchanges for the respective 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 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, 2015, 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,		Effect of 10%		Effect of 10%
	2015		Price Increase		Price Decrease
Exchange traded derivative contracts	$	95,367	$	(34,583)	$	34,583
Forward derivative contracts		34,188		(2,403)		2,403
	$	129,555	$	(36,986)	$	36,986

The fair values of the futures contracts are based on quoted market prices obtained from the NYMEX, CME and ICE. The fair value of the swaps and option contracts are estimated based on quoted prices from various sources such as independent reporting services, industry publications and brokers. These quotes are compared to the contract price of the swap, which approximates the gain or loss that would have been realized if the contracts had been closed out at December 31, 2015. 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 $31.3 million at December 31, 2015.

We are exposed to credit loss in the event of nonperformance by counterparties to our exchange‑traded derivative contracts, physical 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. Exchange‑ traded derivative contracts, the primary derivative instrument utilized by us, are traded on regulated exchanges, greatly reducing potential credit risks. We utilize primarily three clearing brokers, all major financial institutions, for all NYMEX, CME and ICE derivative transactions and the right of offset exists with these financial institutions. Accordingly, the fair value of our exchange‑traded derivative instruments is presented on a net basis in the consolidated balance sheet. Exposure on physical forward contracts and swap agreements is limited to the amount of the recorded fair value as of the balance sheet dates.

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.

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

None.

Item 9A. Controls and Procedures.

Disclosure Controls and Procedures

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, our principal executive officer and principal financial officer concluded as of December 31, 2015 that our disclosure controls and procedures were effective at the reasonable assurance level.

Internal Control Over Financial Reporting

Management’s Annual Report

We are responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a‑15(f) or 15d‑15(f) of the Exchange Act). Internal control over financial reporting is the process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP.

There are inherent limitations in the effectiveness of internal control over financial reporting, including the possibility that misstatements may not be prevented or detected. Accordingly, even effective internal controls over financial reporting can provide only reasonable assurance with respect to financial statement preparation.

Under the supervision and with the participation of our principal executive officer and principal financial officer, management conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework). Based on our internal review, steps to remediate the material weakness in our internal control over financial reporting (discussed below) and additional procedures pursued by management to ensure the reliability of our financial reporting, we believe that the consolidated financial statements in this Form 10-K fairly present, in all material respects, our financial position, results of operations and cash flows as of the dates, and for the periods, presented in conformity with GAAP.

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

Changes in Internal Control

Except for the remediation efforts described below, there has not been any change in our internal control over financial reporting that occurred during the quarter ended December 31, 2015 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Remediation of Prior Year Material Weakness

For the year ended December 31, 2014, management concluded that a material weakness existed in our internal control over reporting (as defined in Rule 13a-15(f) under the Exchange Act). A material weakness is a deficiency, or a

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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, at December 31, 2014, management’s review of the valuation of forward commodity purchase and sales contracts was not sufficiently precise; however, the lack of precision during the performance of the control resulting in this material weakness did not have an impact on the December 31, 2014 financial statements. In 2015, we put in place timely controls and developed systems and designed controls to improve the process of the valuation protocol which enhanced the quality of management’s review of these valuations. As a result of these changes in internal controls over financial reporting and subsequent testing of such controls throughout 2015, we determined that these controls are operating effectively and the material weakness with respect to internal control over financial reporting at December 31, 2014 described above was successfully remediated in 2015.

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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, 2015, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 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 partnership 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.

In our opinion, Global Partners LP has maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, based on the COSO criteria. 

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the 2015 consolidated balance sheets as of December 31, 2015 and 2014 and the related consolidated statements of operations, comprehensive income, partners’ equity and cash flows for each of the three years in the period ended December 31, 2015 of Global Partners LP and our report dated February 29, 2016 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Boston, Massachusetts

February29, 2016

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Item 9B. Other Information.

On February 24, 2016, we and certain of our subsidiaries entered into the fifth amendment to our credit agreement (the “Fifth Amendment”). The Fifth Amendment includes certain modifications to our credit agreement to (i) amend the definition of “Total Combined Leverage Ratio” to permit for an increased maximum ratio of 5.50:1.00 through the first quarter of 2017 and 5.00:1.00 thereafter, (ii) amend the definition of “Applicable Revolver Rate” to align the pricing levels with the amended Total Combined Leverage Ratio maximum thresholds, (iii) increase the permitted level of asset Dispositions (as it is defined in the credit agreement) from $100.0 million to $150.0 million, and (iv) incorporate acknowledgement of and consent to the applicability of European Union Bank Recovery and Resolution Directive bail-in legislation. 

Unrelated to the foregoing modifications, the Fifth Amendment also reflects our voluntary election to reduce our working capital revolving credit facility from $1.0 billion to $900.0 million and our revolving credit facility from $775.0 million to $575.0 million.

All other material terms of our credit agreement remain the same as disclosed in this report.

The foregoing description of the Fifth Amendment does not purport to be complete and is qualified in its entirety by reference to the Fifth Amendment, a copy of which is filed as Exhibit10.47 hereto and incorporated herein by reference.

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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 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. McCool, McKown 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 to establish a compensation committee or a nominating/corporate governance committee.

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

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

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

All of our executive officers devote substantially all of their time to managing our business and affairs, but from time to time perform services for certain of our affiliates. Please read Item 13, “Certain Relationships and Related Transactions, and Director Independence—Relationship of Management with Global Petroleum Corp. and AE Holdings Corp.” Our non‑management directors devote as much time as is necessary to prepare for and attend board of directors and committee meetings.

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Set forth below are the names, ages (as of February 25, 2016) and titles of persons currently serving as directors and executive officers of our general partner:

Name	Age	Position with Global GP LLC
Richard Slifka	75	Chairman
Eric Slifka	50	President, Chief Executive Officer and Director
Andrew Slifka	47	Executive Vice President and Director
Mark A. Romaine	47	Chief Operating Officer
Daphne H. Foster	58	Chief Financial Officer
Edward J. Faneuil	63	Executive Vice President, General Counsel and Secretary
Charles A. Rudinsky	68	Executive Vice President and Chief Accounting Officer
David K. McKown	78	Director
Robert J. McCool	77	Director
Kenneth I. Watchmaker	73	Director

Richard Slifkawas 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 December1998. Mr. Slifka also is a shareholder, a director and the President of Global Petroleum Corp., a privately held affiliated company that had owned, operated and leased to us our petroleum products storage terminal located in Revere, Massachusetts until we acquired the terminal in January 2015. Mr. Slifka is a past director of the New England Fuel Institute and currently serves as president of the 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. Richard Slifka is the brother of the late Alfred A. Slifka.

Eric Slifkawas elected President, Chief Executive Officer and director of Global GPLLC, the general partner of Global PartnersLP, in March 2005. He has been employed with Global CompaniesLLC or its predecessors since 1987. Mr. Slifka served as President and Chief Executive Officer and a director of Global CompaniesLLC since July 2004 and as Chief Operating Officer and a director of Global CompaniesLLC 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 CompaniesLLC. He is a member of the National Petroleum Council and serves on the board of directors of the Energy Policy Research Foundation,Inc., the Massachusetts Youth Committed to Winning and Massachusetts General Hospital President’s Council. Mr. Slifka is the son of the late Alfred A. Slifka and the nephew of Richard Slifka. 

Andrew Slifkawas elected to serve as a director of our general partner in April 2012 and has been serving as Executive Vice President of our general partner since March 2012 and President of Alliance EnergyLLC and its predecessor Alliance Energy Corp. since November 2007. He has been employed with Alliance since 1999. Mr.Slifka served as Vice President and General Manager for the Northeast region (RI, MA, NH, and ME) of Alliance Energy Corp. from 1999 to 2003 and as Executive Vice President of Alliance Energy Corp. 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 NECSEMA (New England Convenience Store & Energy Marketers Association), the National Multiple Sclerosis Society, the CF & MS Fund Foundation Inc. and is on the board of trustees of The Rivers School. Additionally, Mr.Slifka is a member of the ExxonMobil National Council. Mr. Slifka is the son of Richard Slifka and the nephew of the late Alfred A. Slifka.

Mark A. Romainehas been Chief Operating Officer of our general partner since July 2013. Mr. Romaine served as the Senior Vice President of Light Oil Supply and Distribution for our general partner from 2006 until June 2013. He joined Global CompaniesLLC, a predecessor to Global PartnersLP, in 1998 as Premium Fuels Marketing Manager. His experience in the petroleum products industry includes operations and marketing positions with Plymouth, MA-based Volta Oil. Mr. Romaine received a bachelor’s degree from Providence College and an MBA from the University of Massachusetts.

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Daphne H. Fosterhas been Chief Financial Officer of our general partner since July 2013. Ms.Foster served as Treasurer of our general partner from 2010 until June 2013. She joined Global PartnersLP 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. She 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. Faneuilwas 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 previously served as Executive Vice President and General Counsel of Alliance Energy LLC (now a wholly owned subsidiary of Global Partners LP). Mr. Faneuil received a bachelor’s degree from Trinity College and a J.D. from Suffolk University Law School.

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 Executive Vice President, 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. Mr. Rudinsky earned a bachelor’s degree from Boston College and an MBA from Babson College.

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 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 had served as an Advisor to Tetco Inc., a privately held company in the energy industry, for 46 years and 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

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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, regional partner in charge of audit 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, 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 (“Reporting Persons”) 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 all Reporting Persons complied with all Section 16(a) filing requirements in the year ended December 31, 2015, with the exception of two Form 4s for our general partner (with respect to the delivery of common units pursuant to our LTIP) and one Form 4 for Mr. KennethI. Watchmaker (with respect to an acquisition of common units).

Executive Sessions

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

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/oCorporate Secretary, Global Partners LP, P.O. Box 9161, 800South Street, Suite 500, Waltham, MA 02454‑9161, Fax: 781‑398‑4165.

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

Code of Ethics

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

A copy of the code of business conduct and ethics is available on our website at www.globalp.com or may be obtained without charge upon written request to the General Counsel at: Global Partners LP, P.O. Box 9161, 800South Street, Suite 500, Waltham, MA 02454‑9161.

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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 2015.

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 who are employed by Global Montello Group Corp. (“GMG”), and certain union personnel. 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.

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 also are eligible to participate in employee benefit plans and arrangements sponsored by our general partner or its affiliates, including plans that may be established by our general partner or its affiliates in the future. Our named executive officers (defined below) serve as executive officers of our general partner and each of our 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”), Ms. Daphne H. Foster, our Chief Financial Officer (“CFO”), Mr. Mark A. Romaine, our Chief Operating Officer (“COO”), and the three most highly compensated executive officers of our general partner other than our CEO, CFO and COO during 2015, who were Mr. Andrew Slifka, our Executive Vice President and President of our Gasoline Distribution and Station Operations Division (“GDSO”), Mr. Edward J. Faneuil, our Executive Vice President and General Counsel, and Mr. Charles A. Rudinsky, our Executive Vice President and Chief Accounting Officer. Each of Messrs. Eric Slifka, Andrew Slifka, Faneuil and Romaine and Ms. Foster has an employment agreement with our general partner. Mr. Rudinsky is an employee at will and does not have 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 five of our named executive officers.

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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 a third-party compensation consultant to study and supply market compensation data and to assist our management and the Compensation Committee in formulating competitive compensation plans and arrangements. The Compensation Committee retained BDO USA, LLP (“BDO”) as its outside compensation consultant during 2015.

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

· Our Executive Vice President and General Counsel plays a critical role in our major transactions and strategic business initiatives, serves as a trusted business advisor to our executive officers, and is responsible for all of our environmental compliance functions, as well as serving as our top legal executive;

· 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 GDSO Division has executive responsibilities as well as primary oversight of our gasoline and convenience store business.

Overall Partnership performance and individual performance may cause the targeted compensation levels to be adjusted up or down accordingly.

BDO worked with the Compensation Committee in 2016 to update the performance targets and associated levels of payouts previously contained in our short-term incentive plan for our named executive officers (the “STIP”) for 2015. Plan modifications were made to incorporate the increased scope of our operations and to ensure that the plan is fully aligned and consistent with our efforts to achieve critical business objectives. A complete description of changes made to the STIP is included in the next section,—Elements of Compensation.

During 2015, BDO worked with the Compensation Committee to provide updated performance targets and related award levels for our general partner’s 2015 STIP to ensure that the plan is fully aligned with our critical business objectives; to research and prepare a competitive compensation assessment for our Chief Financial Officer position and a competitive assessment of methods and levels of compensation for independent board members; and to assist with compensation information related to this Form 10-K. During 2014, BDO provided competitive information and assistance related to the renewal of employment agreements for Messrs. Eric Slifka, Andrew Slifka and Edward Faneuil.

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Analyses regarding competitive pay practices for our named executive officers and board members were based on information from several groups of companies with various characteristics comparable and relevant to our current size and scope of operations.

Highlights of Compensation Program Policies for Named Executive Officers

· A significant portion of total direct compensation for our named executive officers is variable, dependent upon the Partnership's actual performance (e.g., short-term, performance-based incentives and long-term, equity-based incentives);

· Prohibition on repricing of options and unit appreciation rights unless approved by unitholders;

· The Compensation Committee engages the assistance of an independent compensation consultant; and

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

The elements of the 2015 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 five of our named executive officers are set by the terms of their respective employment agreements; the base salary for the named executive officer without an employment agreement is set in accordance with our CEO’s recommendation, using salary range information from BDO, and as approved by the Compensation Committee. Base salaries for our named executive officers did not change in 2015. The base salaries in effect as of the end of 2015 for our named executive officers were as follows: $800,000 for Mr. Eric Slifka, $500,000 for Mr. Romaine; $450,000 for Mr. Faneuil; $425,000 for Mr. Andrew Slifka; $400,000 for Ms. Foster; and $273,000 for Mr. Rudinsky.

Short-Term Incentive Plans

Our general partner established a cash bonus pool for 2015 to fund short-term incentive awards for each of our named executive officers. Target awards under our general partner’s 2015 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 2015 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 2015 (the “DCF objective”). Under the STIP, 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

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“Results of Operations—Key Performance Indicators” in Item 7, “Management's Discussion and Analysis of Financial Conditions and Results of Operations.”

Under the STIP, each of our named executive officers was assigned an incentive target value expressed as a percentage of his or her base salary. The 2015 incentive target values were: 100% (or $800,000) for Mr. Eric Slifka; 100% (or $500,000) for Mr. Romaine; 100% (or $450,000) for Mr. Faneuil; 75% (or $300,000) for Ms. Foster; 62% (or $265,000) for Mr. Andrew Slifka; and 41% (or $112,500) for Mr. Rudinsky. 50% of the incentive target value 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 but exceeds a certain DCF minimum threshold, 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. In 2015 we failed to achieve the minimum threshold of DCF required to qualify for any incentive payout under the STIP Performance Component, and therefore no STIP Performance Component awards were made in 2015.

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 that it may elect to use for determining the STIP Performance Component. Such factors may include, without limitation, market factors and significant acquisitions, developments and ventures accomplished by us, management of our business in the face of adverse market conditions and, as may be applicable, the contributions of any or all of the named executive officers. Mr. Eric Slifka’s evaluation of our named executive officers’ performance in 2015 included the recognition that they worked extremely hard and as a team, and that the Partnership’s performance in 2015 was not an indication that our named executive officers underperformed. Taking into account Mr. Slifka’s assessment, the Partnership’s results of operations for 2015, as well as the Compensation Committee’s review of the individual performance of our named executive officers in 2015, no awards were made under the STIP Discretionary Component for 2015.

In considering whether to grant the 2015 STIP Discretionary Component awards, the Compensation Committee recognized that our business performance was significantly below that of the prior year due to tighter crude oil differentials and the negative impact of fixed costs associated primarily with our significantly underutilized leased railcar fleet, the less favorable conditions in the wholesale gasoline blendstocks and renewable fuels markets and the unusually warm weather conditions. Notwithstanding the foregoing, the following actions were undertaken by us under the leadership of Mr. Eric Slifka and executed by our named executive officers to expand our retail presence and terminal network and to restructure our financing, including:

· On January 7, 2015, we completed the acquisition of 100% of the capital stock of Warren Equities, Inc. and its subsidiaries. This acquisition is the largest in our history and included 147 company-owned Xtra Mart convenience stores and related fuel operations, 53 commission agent locations and fuel supply rights for approximately 330 dealers. As part of the subsequent integration of this acquisition, we realized, and continue to realize, economies of scale and synergies between our GDSO business and the newly acquired businesses.

· On January 15, 2015, we acquired the storage and distribution terminal located in Boston Harbor in Revere, Massachusetts which has been operated on our behalf since the inception of the Partnership, and which has a storage capacity of 2.1 million barrels of refined petroleum products, including heating oil, gasoline, distillates, diesel, kerosene and blendstocks.

· On June 1, 2015, we expanded our retail footprint into New York City and Prince George’s County, Maryland by acquiring 97 primarily Mobil and Exxon branded retail gas stations and seven dealer supply

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contracts, along with certain related supply, franchise agreements, third party leases and other assets associated with these operations;

· On June 4, 2015, we completed a private placement of $300.0 million aggregate principal amount of 7.0000% senior notes due 2023, the proceeds of which were used to reduce our indebtedness, and on October 21, 2015, we completed an exchange of the aforementioned private notes for $300.0 million aggregate principal amount of registered 7.0000% senior notes due 2023.

· On June 16, 2015, we completed a public offering of 3,000,000 common units representing limited partner interests in the Partnership, the proceeds of which were used to reduce our indebtedness.

2016 Short-Term Incentive Plan.—In 2016, the Compensation Committee, with the assistance of its compensation consultant, BDO, used our 2015 Short-Term Incentive Plan as a basis for creating the 2016 Short-Term Incentive Plan. The 2016 STIP establishes a target incentive percentage for each participant ranging from 41% to 100% of base salary representing the same target percentages used during 2015 for the named executive officers. Awards under the 2016 STIP may range from 0% to 200% of each participant's target incentive percentage. The weighting of the STIP Performance Component and STIP Discretionary Component in the 2016 STIP remain 50% and 50%, respectively, the same as in the 2015 STIP.

· The 2016 Performance Component (50% of the incentive target value)—The Compensation Committee slightly decreased the DCF objective for 2016, subject to adjustment by the Compensation Committee for certain acquisitions and events during 2016 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 2016 STIP Performance Component. A minimum of 80%of the 2016 DCF objective must be achieved before participants would earn any portion of the 2016 STIP Performance Component. Under the 2016 STIP, a participant's incentive opportunity increases to a maximum of 200% of the STIP Performance Component at 128% of the 2016 DCF objective, and is determined on a quantitative basis solely based on our actual DCF for 2016. 

· The 2016 Discretionary Component (50% of the incentive target value)—The Compensation Committee has discretion in determining the 2016 STIP Discretionary Component for any participant under the 2016 STIP, within a range of 0% to 200% of the 2016 STIP Discretionary Component, and based upon (i) the Compensation Committee’s consideration of management's performance over the course of the 2016 plan year; (ii) the CEO’s assessment of the other named executive officers; (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 on an individual basis. 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. 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 respect of our named executive officers’ service in 2015. The Compensation Committee awarded Messrs. Eric Slifka, Romaine and Faneuil, Ms. Foster, Mr. Andrew Slifka and Mr. Rudinsky special discretionary bonuses in the amounts of $600,000, $500,000, $400,000, $300,000, $200,000 and $100,000, respectively, for their service in 2014. The Compensation Committee did not award any discretionary bonus payments in respect of our named executive officers’ service in 2013.

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Long-Term Incentive Plans

2015 Awards.—No equity grants were made under the Global Partners LP Long-Term Incentive Plan (“LTIP”) to any of our named executive officers in respect of their service in 2015.

2014 Awards.—No equity grants were made under the LTIP to any of our named executive officers in respect of their service in 2014.

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. Mr. Rudinsky is party to an executive change of control agreement with our general partner which includes additional acceleration provisions. Please read “—Employment and Related Agreements” for additional information with respect to Mr. Rudinsky’s executive change of control agreement.

2012 CEO Performance-Based Cash Incentive Plan.—Mr. Eric Slifka’s 2012-2014 employment agreement with our general partner included provisions for a long-term performance-based cash incentive plan. The long-term performance-based cash incentive plan was based solely on the achievement of growth in distributions to our unitholders in respect of the three-year term of Mr. Slifka’s 2012-2014 employment agreement. The award was calculated using (i) the sum of all distributions paid to our unitholders in respect of the three-year period from January 1, 2012 through December 31, 2014 (which were made during the period from May 2012 through February 2015), inclusive, and (ii) an annualized $2.00 per unit (subject to adjustment by the Compensation Committee as set forth in Mr. Slifka's employment agreement) baseline against which Mr. Slifka's performance was measured. Mr. Slifka earned $3,450,000 under this incentive plan.

2015 CEO Performance-Based Cash Incentive Plan.—Mr. Eric Slifka’s 2015-2017 employment agreement with our general partner includes provisions for a long-term performance-based cash incentive plan. This plan replaces the plan for the 2012-2014 period described above under “—2012 CEO Performance-Based Cash Incentive Plan” and is also based on the achievement of growth in distributions to our unitholders in respect of the three-year term of Mr. Slifka's 2015-2017 employment agreement. This award will be calculated using (i) the sum of all distributions paid to our unitholders in respect of the three-year period from January 1, 2015 through December 31, 2017 (which are anticipated to be made during the period from April 1, 2015 through March 31, 2018), inclusive, and (ii) an annualized $2.66 per unit (subject to adjustment by the Compensation Committee as set forth in Mr. Slifka's employment agreement) baseline against which Mr. Slifka's performance will be measured.

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Retirement and Health Benefits; Perquisites

Global Partners 401(k) Savings and Profit Sharing Plan

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. The Global 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 eligible compensation. In 2015, all employees were eligible to participate in the Global 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 Global 401(k) Plan, (3) had not been employed by our predecessor, our general partner or one of our operating subsidiaries for at least six months or (4) were nonresident aliens. In 2016, the six month employment requirement described in clause (3) of the preceding sentence was eliminated, so that new employees may begin to contribute to the Global 401(k) Plan on the first day of the month following their respective dates of hire, although they are not eligible to receive matching payments under the Global 401(k) Plan until they have been employed by our general partner or one of our operating subsidiaries for six months. The exceptions to eligibility for participation in the Global 401(k) Plan set forth in clauses (1), (2) and (4) above remain the same. 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.

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 or disability. Please read “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.

Prior to March 1, 2012, Mr. Andrew Slifka was employed by Alliance Energy LLC (“Alliance”) and participates in the Alliance Energy LLC Pension Plan in accordance with Alliance’s policies and on the same general basis as other employees of Alliance not excluded by the terms of the plan. On March 1, 2012, sponsorship of the Alliance Energy LLC Pension Plan was transferred to GMG and renamed as the GMG Pension Plan (as defined and described below under “Other Benefits—Pension Benefits”). 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 or disability. Please read “Other Benefits—Pension Benefits” for information with respect to eligibility standards and calculations of estimated annual pension benefits payable upon retirement under the GMG Pension Plan. The GMG Pension Plan was frozen on May 15, 2012.

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.

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Employment Agreements

Each of Messrs. Eric Slifka, Andrew Slifka, Faneuil and Romaine and Ms. Foster has an employment agreement with our general partner. We believe that the post-termination and change in control payments in the employment agreements allow our named executive officers to focus on making business decisions that maximize our interests and the interests of our unitholders without allowing personal considerations to influence the decision-making process. Please read “Potential Payments upon Termination or Change of Control” for a discussion of the provisions in each employment agreement relating to termination, change in control and related payment obligations.

Relationship of Compensation Elements to Compensation Objectives

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

We use a short-term incentive plan with performance-based and discretionary components to align a significant portion of our executive officers' compensation with annual business performance and success, and to provide rewards and recognition for key business outcomes such as achieving increased quarterly distributions in line with our financial results, 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 (the performance-based cash incentive plans applicable to Mr. Eric Slifka and the 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

February 26,  2016

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Compensation Committee Interlocks and Insider Participation

Since the formation of Global GP LLC and throughout the fiscal year ended December 31, 2015, 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 A. Slifka served as the Chairman of the board of directors of our general partner until his death on March 9, 2014 and until December 31, 2013 was an employee of Global Petroleum Corp., an entity which is owned by Mr. Richard Slifka and the estate of Mr. Alfred A. Slifka. Mr. Richard Slifka, who served as Vice-Chairman of our general partner’s board of directors since its inception, became Chairman effective March 12, 2014 and is an employee of Global Petroleum Corp.

Compensation of Named Executive Officers

The following table sets forth certain information with respect to compensation during 2015, 2014 and 2013 of our named executive officers.

Summary Compensation Table

						Change in
						Pension Value
						and Deferred
				Non‑Equity		Nonqualified
				Incentive Plan	Unit	Compensation	All Other
Name and Principal		Salary	Bonus	Compensation	Awards	Earnings	Compensation	Total
Position	Year	($)(1)	($) (2)	($) (3)	($) (4)	($) (5)	($)(6)	($)
Eric Slifka	2015	800,000	—	—	—	—	87,850	887,850
President and CEO	2014	800,000	600,000	4,938,000	—	55,552	93,212	6,486,764
	2013	800,000	—	400,000	5,000,000	—	73,756	6,273,756
Mark A. Romaine	2015	500,000	—	—	—	—	36,016	536,016
Chief Operating Officer	2014	500,000	500,000	930,000	—	46,446	35,741	2,012,187
	2013	450,000	—	250,000	2,240,000	—	30,965	2,970,965
Edward J. Faneuil	2015	450,000	—	—	—	—	44,762	494,762
EVP, General Counsel	2014	376,000	400,000	651,000	—	165,524	40,340	1,632,864
and Secretary	2013	376,000	—	175,000	3,000,000	—	36,891	3,587,891
Daphne H. Foster	2015	400,000	—	—	—	—	25,869	425,869
Chief Financial Officer	2014	300,000	300,000	372,000	—	5,531	13,714	991,245
	2013	246,500	—	100,000	860,000	—	20,668	1,227,168
Andrew Slifka	2015	425,000	—	—	—	—	51,686	476,686
EVP and President of	2014	425,000	200,000	372,000	—	60,012	52,251	1,109,263
GDSO Division	2013	425,000	—	100,000	1,160,500	—	49,002	1,734,502
Charles A. Rudinsky	2015	273,000	—	—	—	—	34,298	307,298
EVP and Chief	2014	273,000	100,000	209,250	—	19,923	30,742	632,915
Accounting Officer	2013	273,000	—	66,000	245,064	—	28,633	612,697

(1)The above table reflects the $800,000 base salary paid to Mr. Eric Slifka in (i) 2013 and 2014 pursuant to his 2012-2015 employment agreement with our general partner, which became effective January 1, 2012, and (ii) 2015 pursuant to his new employment agreement with our general partner, which became effective January 1, 2015 and under which the amount of his base salary remained unchanged.

(2)In 2015, Messrs. Eric Slifka, Romaine and Faneuil, Ms. Foster, Mr. Andrew Slifka and Mr. Rudinsky were paid discretionary bonuses of $600,000, $500,000, $400,000, $300,000, $200,000 and $100,000, respectively, for services performed during 2014, which discretionary bonuses were in addition to the payments they received in 2015 for services performed during 2014 under the 2014 Short-Term Incentive Plan. No discretionary bonuses were paid for services performed during 2013.

(3)Amounts reported in this column reflect (a) the bonuses paid to each of the named executive officers for services performed during 2015, 2014 and 2013 which were determined in accordance with our general partner’s Short-Term Incentive Plans described above under “Elements of Compensation—Short-Term Incentive Plans” and (b) for

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Mr. Eric Slifka, $3,450,000, which was earned under the long-term performance-based cash incentive plan under his 2012-2014 employment agreement and is described above under “Elements of Compensation—Long-Term Incentive Plans”.

(4)All of our equity grant awards were made under the LTIP. 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, “Compensation – Stock Compensation,” 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.

(5)As a result of higher interest rates used to calculate pension benefits, the present value of Mr. Eric Slifka's pension decreased by (i) $41,884 in 2015, and the present values of the pensions of Messrs. Romaine and Faneuil, Ms. Foster, Mr. Andrew Slifka and Mr. Rudinsky decreased in 2015 by $50,235, $321,081, $2,551, $73,459 and $75,919, respectively; and (ii) $53,379 in 2013, and the present values of the pensions of Messrs. Faneuil, Andrew Slifka and Rudinsky decreased in 2013 by $20,580, $31,277, and $57,755, respectively. Additionally, the present value of Mr. Faneuil’s pension in 2015 reflected a reduction equal to the net present value of his vested SERP, which is $159,355. 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”.

(6)The 2015 amounts in this column are described further in the All Other Compensation table below.

All Other Compensation Table

The following table describes each component of the “All Other Compensation” column of the Summary Compensation Table for the fiscal year ended December 31, 2015:

		Club Membership Dues,
	Employer	Legal Fees, and Professional
	Contributions to	Financial Planning and	Personal	Total All
	Global 401(k) Plan	Tax Advice Fees	Benefits (1)	Other Compensation
Name	($)	($)	($)	($)
Eric Slifka	8,000	41,742	38,109	87,851
Mark A. Romaine	8,000	—	28,016	36,016
Edward J. Faneuil	10,600	16,634	17,528	44,762
Daphne H. Foster	10,600	—	15,269	25,869
Andrew Slifka	10,600	18,200	22,886	51,686
Charles A. Rudinsky	10,600	—	23,698	34,298

(1)The amounts in this column include the estimated incremental cost of an automobile provided by us for the named executive officer’s use; medical and dental premiums paid by us; and life insurance and long-term disability premiums paid by us. 

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Grants of Plan-Based Awards

During 2016, the Compensation Committee determined that no grants of STIP awards had been earned in respect of our named executive officers’ service during the year ended December 31, 2015. During 2015, the Compensation Committee granted cash awards under our general partner’s 2014 STIP to our named executive officers in consideration of their respective services during the year ended December 31, 2014. Please read “Elements of Compensation—Short-Term Incentive Plan” for a discussion of the parameters on which the 2015 awards were determined.

No equity awards were made under the LTIP to any of our named executive officers in 2015.

The following table sets forth information concerning criteria for the grant of plan-based awards during the calendar year 2015 to our named executive officers from the STIP (including the minimum threshold, target and maximum possible payout amounts, depending upon our financial performance in 2015).

Grants of Plan‑Based Awards

	Estimated Possible Payouts Under
	Non—Equity Incentive Plan Awards
	Minimum
	Threshold		Maximum
Name	($)	Target ($)	($)
Eric Slifka	40,000	800,000	1,600,000
Mark A. Romaine	25,000	500,000	1,000,000
Edward J. Faneuil	22,500	450,000	900,000
Daphne H. Foster	15,000	300,000	600,000
Andrew Slifka	13,250	265,000	530,000
Charles A. Rudinsky	5,625	112,500	225,000

Outstanding Equity Awards at Fiscal Year End

The following table presents the full amount of the equity awards held by our named executive officers as of December 31, 2015, which consist solely 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:

	Equity Incentive Plan Awards
		Market or Payout
	Number of	Value of
	Unearned Shares,	Unearned Shares,
	Units or Other	Units or Other
	Rights That Have	Rights That Have
	Not Vested (#) (1)	Not Vested ($) (2)
Eric Slifka	127,259	2,235,941
Mark A. Romaine	57,012	1,001,701
Edward J. Faneuil	76,356	1,341,575
Daphne H. Foster	21,889	384,590
Andrew Slifka	29,537	518,965
Charles A. Rudinsky	2,122	37,284

(1)The units granted to each named executive officer 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 having vested on December 31, 2014, one-third having vested on December 31, 2015 and one-third scheduled to vest on December 31, 2016.

(2)The market values of the equity awards shown in the table above were calculated based on the closing price of $17.57 per common unit on December 31, 2015.

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Please read “Elements of Compensation—Long-Term Incentive Plans” for a discussion of these phantom unit awards.

Units Vested in the 2015 Fiscal Year

The following table presents phantom units awarded to the named executive officers on June 27, 2013 and September 23, 2013 that vested during the year ended December 31, 2015.

	Equity Incentive Plan Awards
	Number of
	Vested	Market Value of Vested
	Phantom Units	Phantom Units (#) ($) (1)
Charles A. Rudinsky	2,121	37,266

(1)These units vested on December 31, 2015. The market values of the equity awards shown in the table above were calculated based on the closing price of $17.57 per common unit on December 31, 2015, when the units vested.

Nonqualified Deferred Compensation

Mr. Romaine 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 2015 and the aggregate sum of installment payments to be paid to Mr. Romaine after 2015 in respect of his prior bonuses.

Nonqualified Deferred Compensation 

	Aggregate Withdrawals /		Aggregate Balance at Last FY
Name	Distributions (1)		End (2)
Mark A. Romaine	$	337,500	$	—

(1) The amount reported in this column reflects the deferred installment payments of the bonuses earned by Mr. Romaine in 2010, 2011 and 2012 that were paid to Mr. Romaine in 2015.

(2) The amount reported in this column reflects that there are no deferred installment payments to be paid to Mr. Romaine after 2015 in respect of his prior years’ awarded bonuses.

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”). Please read “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”). Please read “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 a SERP agreement with Edward J. Faneuil. Mr. Faneuil's SERP benefit became fully vested on December 31, 2014. The value of the SERP benefit to be provided under the agreement, expressed as a single lump sum payment, is $159,355 for Mr. Faneuil.

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Potential Payments upon a Change of Control or Termination

The following tables show potential payments to each of our named executive officers under existing contracts, agreements, plans or arrangements, whether written or unwritten, for various scenarios involving a change of control or termination of employment of each such named executive officer assuming a December 31, 2015 termination date. This table does not take into account discretionary decisions regarding compensation made by the Compensation Committee and the board of directors of our general partner made after December 31, 2015. Amounts reflected in the table below with respect to LTIP awards were calculated based on the closing price of our common units of $17.57 per unit on December 31, 2015.

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 an additional 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, which is reflected appropriately in the tables below. Please read “Elements of Compensation—Long-Term Incentive Plan” for information regarding performance restrictions and additional vesting terms.

Eric Slifka

				Termination by general
				partner without Cause /
				Constructive Termination /
				Breach by general partner
	Change in			No Change	With a Change
	Control	Death	Disability	in Control	in Control	Nonrenewal
Name	($)	($)	($)	($)	($)	($)
Eric Slifka
Severance Amount	—	—	—	—	—	—
Long Term Cash Incentive Plan	—	3,200,000	3,200,000	3,200,000	4,800,000	800,000
LTIP awards	2,235,941	—	—	—	2,235,941	—
Fringe benefits	—	39,672	39,672	39,672	39,672	—
Life insurance benefits	—	500,000	—	—	—	—
Total	2,235,941	3,739,672	3,239,672	3,239,672	7,075,613	800,000

If Mr. Slifka’s employment is terminated for any reason, he shall be paid (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, including vacation pay, that may be due to him as of the date of termination (the “Eric Slifka Accrued Obligations”).

If Mr. Slifka’s employment is terminated by death or “Disability” (as defined in the employment agreement), he (or his estate) will be paid (i) the Eric Slifka Accrued Obligations, plus (ii) a lump sum payment equal to his then base salary multiplied by 200%, plus (iii) an amount equal to the target incentive amount under the then applicable short-term incentive plan multiplied by 200%, plus (iv) his interests in the long-term incentive plans, including (a) the pro-rated cash incentive amount, if any, earned under the Long-Term Performance-Based Cash Incentive Plan and (b) the amounts of cash and/or securities due as a result of the automatic vesting of Mr. Slifka’s interests in the Long-Term Equity-Based Incentive Plan, plus (v) group health and similar insurance premiums on behalf of his spouse and dependents for 24 months following the date of termination.

If Mr. Slifka’s employment is terminated by our general partner without “Cause” or by Mr. Slifka for reasons constituting “Constructive Termination,” each as defined in the employment agreement, he shall be paid (i) the Eric Slifka Accrued Obligations, plus (ii) a lump sum payment equal to his then base salary multiplied by 200% (provided, however, that this multiplier shall be 300% if Mr. Slifka terminates his employment for reasons constituting Constructive Termination and such termination occurs within 12 months following a “Change in Control” (as defined in the employment agreement), plus (iii) an amount equal to the target incentive amount under the then applicable short-term

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incentive plan multiplied by 200% (provided, however, that this multiplier shall be 300% if Mr. Slifka terminates his employment for reasons constituting Constructive Termination and such termination occurs within 12 months following a Change in Control), plus (iv) his interests in the long-term incentive plans, including (a) the pro-rated cash incentive amount, if any, earned under the Long-Term Performance-Based Cash Incentive Plan and (b) the amounts of cash and/or securities due as a result of the automatic vesting of Mr. Slifka’s interests in the Long-Term Equity-Based Incentive Plan, plus (v) group health and similar insurance premiums on behalf of his spouse and dependents for 24 months following the date of termination.  If Mr. Slifka terminates his employment for reasons of Constructive Termination but such termination does not occur within 12 months following a Change in Control and Mr. Slifka secures employment within 12 months of the date of termination, he shall repay to our general partner one-half of the cash received from our general partner pursuant to (ii) and (iii) above.

If Mr. Slifka’s employment is terminated by our general partner for Cause, Mr. Slifka will be paid the Eric Slifka Accrued Obligations. If Mr. Slifka’s employment agreement is not renewed by our general partner and he does not continue to serve as our general partner’s President and Chief Executive Officer following the expiration of his employment agreement, he shall be paid the Eric Slifka Accrued Obligations plus a lump sum payment equal to 100% of his then base salary.

Mark A. Romaine

				Termination by general
				partner without Cause /
				Constructive Termination /
				Breach by general partner
	Change in			No Change	With a Change
	Control	Death	Disability	in Control	in Control	Nonrenewal
Name	($)	($)	($)	($)	($)	($)
Mark A. Romaine
Severance Amount	—	—	—	1,000,000	2,000,000	—
LTIP awards	1,001,701	—	—	—	1,001,701	—
Fringe benefits	—	36,016	—	60,655	60,655	—
Life insurance benefits	—	500,000	—	—	—	—
Total	1,001,701	536,016	—	1,060,655	3,062,356	—

The employment agreement with Mr. Romaine may be terminated at any time by either party with proper notice. If Mr. Romaine’s employment is terminated for any reason, Mr. Romaine will receive payment through the date of termination 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 in accordance with the established plans and policies of our general partner or applicable law (the “Romaine Accrued Obligations”).

If Mr. Romaine’s employment is terminated by our general partner without “Cause” or by Mr. Romaine for “Constructive Termination” (each quoted term as defined in the employment agreement), Mr. Romaine shall be entitled to receive the Romaine Accrued Obligations plus a severance payment in an amount equal to the sum of (i) twice his then base salary, plus (ii) if such termination occurs within 12 months following a “Change in Control” (as defined in the employment agreement), an amount equal to twice the target incentive amount under the then applicable short-term incentive plan for the fiscal year in which the termination occurs. In addition, our general partner shall provide health care continuation coverage benefits to Mr. Romaine and would continue to pay the applicable percentage of the medical insurance premiums that it pays for active employees during the applicable coverage period (not to exceed 18 months).

Further, if Mr. Romaine’s employment is terminated by our general partner without Cause or by Mr. Romaine for Constructive Termination at any time within three months before a Change in Control and 12 months following a Change in Control, then Mr. Romaine will receive the Romaine Accrued Obligations plus 100% accelerated vesting on any and all outstanding 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.

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If Mr. Romaine’s employment is terminated by our general partner for “Cause,” by Mr. Romaine voluntarily (for reasons other than Constructive Termination) or by reason of death, Mr. Romaine shall receive the Romaine Accrued Obligations.

Edward J. Faneuil

				Termination by general
				partner without Cause /
				Constructive Termination /
				Breach by general partner
	Change in			No Change	With a Change
	Control	Death	Disability	in Control	in Control	Nonrenewal
Name	($)	($)	($)	($)	($)	($)
Edward J. Faneuil
Severance Amount	—	—	—	900,000	1,800,000	—
Deferred Compensation	1,638,898	1,638,898	1,638,898	1,638,898	1,638,898	—
LTIP awards	1,341,575	—	—	—	1,341,575	—
Fringe benefits	—	—	—	44,762	44,762	—
Life insurance benefits	—	500,000	—	—	—	—
Total	2,980,473	2,138,898	1,638,898	2,583,660	4,825,235	—

The employment agreement with Mr. Faneuil may be terminated at any time by either party with proper notice.If Mr. Faneuil’s employment is terminated 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 “Faneuil Accrued Obligations”).

If Mr. Faneuil’s employment is terminated by our general partner without “Cause” or by Mr. Faneuil for “Constructive Termination,” each as defined in the employment agreement, he shall be entitled to receive the Faneuil Accrued Obligations plus a severance payment in an amount equal to the sum of (i) twice his then base salary, plus (ii) if such termination occurs within 12 months following a “Change in Control” (as defined in the employment agreement), an additional amount equal to twice his target incentive amount under the then applicable short-term incentive plan for the fiscal year in which the termination occurs. In addition, our general partner would provide health care continuation coverage benefits to Mr. Faneuil and would continue to pay the applicable percentage of the medical insurance premiums that it pays for active employees during the applicable coverage period (not to exceed 18 months).

If Mr. Faneuil’s employment is terminated by our general partner without Cause or by Mr. Faneuil for Constructive Termination at any time within three months before a Change in Control and 12 months following a Change in Control, then Mr. Faneuil will receive the Faneuil Accrued Obligations plus100% accelerated vesting on any and all outstanding 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.

If Mr.Faneuil’s employment is terminated by our general partner for “Cause,” by Mr.Faneuil voluntarily (for reasons other than Constructive Termination) or by reason of death, Mr.Faneuil shall receive the Faneuil Accrued Obligations.

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

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event that 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, 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, 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 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.

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 the employment agreement. 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.

Daphne H. Foster

				Termination by general
				partner without Cause /
				Constructive Termination /
				Breach by general partner
	Change in			No Change	With a Change
	Control	Death	Disability	in Control	in Control	Nonrenewal
Name	($)	($)	($)	($)	($)	($)
Daphne H. Foster
Severance Amount	—	—	—	800,000	1,400,000	—
LTIP awards	384,590	—	—	—	384,590	—
Fringe benefits	—	25,869	—	27,219	27,219	—
Life insurance benefits	—	500,000	—	—	—	—
Total	384,590	525,869	—	827,219	1,811,809	—

The employment agreement with Ms. Foster may be terminated at any time by either party with proper notice. If Ms. Foster’s employment is terminated for any reason, Ms. Foster will receive payment through the date of termination 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 in

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accordance with the established plans and policies of our general partner or applicable law (the “Foster Accrued Obligations”).

If Ms. Foster’s employment is terminated by our general partner without “Cause” or by Ms. Foster for “Constructive Termination” (each quoted term as defined in the employment agreement), Ms. Foster shall be entitled to receive the Foster Accrued Obligations plus a severance payment in an amount equal to the sum of (i) twice her then base salary, plus (ii) if such termination occurs within 12 months following a “Change in Control” (as defined in the employment agreement), an amount equal to twice the target incentive amount under the then applicable short-term incentive plan for the fiscal year in which the termination occurs. In addition, our general partner shall provide health care continuation coverage benefits to Ms. Foster and would continue to pay the applicable percentage of the medical insurance premiums that it pays for active employees during the applicable coverage period (not to exceed 18 months).

Further, if Ms. Foster’s employment is terminated by our general partner without Cause or by Ms. Foster for Constructive Termination at any time within three months before a Change in Control and 12 months following a Change in Control, then Ms. Foster will receive the Foster Accrued Obligations plus100% accelerated vesting on any and all outstanding options, restricted units, phantom units, unit appreciation rights, and other similar rights (under the LTIP or otherwise) held by her as in effect on the date of termination.

If Ms. Foster’s employment is terminated by our general partner for “Cause,” by Ms. Foster voluntarily (for reasons other than Constructive Termination) or by reason of death, Ms. Foster shall receive the Foster Accrued Obligations.

Andrew Slifka

				Termination by general
				partner without Cause /
				Constructive Termination /
				Breach by general partner
	Change in			No Change	With a Change
	Control	Death	Disability	in Control	in Control	Nonrenewal
Name	($)	($)	($)	($)	($)	($)
Andrew Slifka
Severance Amount	—	850,000	1,383,250	1,383,250	1,383,250	612,698
LTIP awards	518,965	—	—	—	518,965	—
Fringe benefits	—	103,372	103,372	103,372	103,372	—
Life insurance benefits	—	500,000	—	—	—	—
Total	518,965	1,453,372	1,486,622	1,486,622	2,005,587	612,698

If Mr. Slifka’s employment is terminated for any reason, he shall be paid (i) all amounts of his base salary due and owing up through the date of termination, (ii) any earned but unpaid bonus and short-term cash incentive plan amounts, (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 “Andrew Slifka Accrued Obligations”).

If Mr. Slifka’s employment is terminated due to death or “Disability” (as defined in the employment agreement), he (or his estate) shall be paid the Andrew Slifka Accrued Obligations, and continued payment of Mr. Slifka’s base salary as well as all fringe benefits through the end of the applicable term. Furthermore, if Mr. Slifka’s employment is terminated due to his Disability, he shall receive (a) payment of all monthly amounts due for all health and welfare insurance premiums on behalf of Mr. Slifka, his spouse and dependents, if any, for 24 months following the date of termination and (b) payment, payable in 24 equal monthly installments commencing on the last day of the month following the last day of the Term (as defined in the employment agreement), of an amount equal to the product of 75% and the sum of (i) Mr. Slifka’s then base salary and (ii) the average of the aggregate discretionary bonuses and short-term cash incentive plan amounts awarded to Mr. Slifka pursuant to the employment agreement, if any, for the two calendar years immediately preceding the termination of the employment agreement.

If Mr. Slifka’s employment is terminated by our general partner without “Cause” or by Mr. Slifka for reasons constituting “Constructive Termination,” each as defined in the employment agreement, he shall receive(1) the Andrew

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Slifka Accrued Obligations, (2) continuation of all compensation and benefits until the last day of the Term and (3) payment, payable in 24 equal monthly installments commencing on the first day of the month following the month in which the date of termination occurs, of an amount equal to the product of 75% and the sum of (a) Mr. Slifka’s then base salary and (b) the average of the aggregate discretionary bonuses and short-term cash incentive plan amounts awarded to Mr. Slifka pursuant to the employment agreement, if any, for the two calendar years immediately preceding the termination of the employment agreement.

If Mr. Slifka’s employment is terminated by our general partner for “Cause,” Mr. Slifka will be paid the Andrew Slifka Accrued Obligations.

If Mr. Slifka’s employment agreement is not renewed by our general partner at the end of the applicable term and Mr. Slifka does not continue to serve as Executive Vice President of the Company or President of the Partnership’s Gasoline Distribution and Station Operations Division following the expiration of the employment agreement, Mr. Slifka shall be entitled to receive an amount, payable in 12 equal monthly installments, equal to the greater of: (1) the product of 75% and the sum of (a) Mr. Slifka’s then base salary and (b) the average of the aggregate discretionary bonuses and short-term cash incentive plan amounts awarded to Mr. Slifka pursuant to the employment agreement, if any, for the two calendar years immediately preceding the termination of the employment agreement and (2) 100% of Mr. Slifka’s then base salary. Mr. Slifka also shall be entitled to receive an additional amount equal to the sum of (x) 16.67% of his then base salary, and (y) 16.67% of his fringe benefits, to reflect the two months by which the term of his previous employment agreement was shortened.

Charles A. Rudinsky

				Termination by general
				partner without Cause /
				Constructive Termination /
				Breach by general partner
	Change in			No Change	With a Change
	Control	Death	Disability	in Control	in Control	Nonrenewal
Name	($)	($)	($)	($)	($)	($)
Charles A. Rudinsky
LTIP awards	74,550	—	—	—	74,550	—
Fringe benefits	—	—	—	34,298	34,298	—
Life insurance benefits	—	350,000	—	—	—	—
Total	74,550	350,000	—	34,298	108,848	—

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 information, knowledge or data of our general partner or any of its subsidiaries);

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(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.

Other Benefits

Pension Benefits

The table below sets forth information regarding the present value as of December 31, 2015 of the accumulated benefits of our named executive officers under the Global Partners LP Pension Plan, and, with respect to Mr. Faneuil, the Global and Alliance Deferred Compensation Agreements. Amounts with respect to the Global and Alliance Deferred Compensation Agreements are reflected in the table below because they represent a fixed entitlement.

Pension Benefits at December 31, 2015

		Number of Years	Present Value of	Payments During
Name	Plan Name	Credited Service (#)	Accumulated Benefit ($)	Last Fiscal Year ($)
Eric Slifka	(1)	26	433,666	—
Mark A. Romaine	(1)	13	145,840	—
Edward J. Faneuil	(1)	22	589,113	—
Edward J. Faneuil	(2)	n/a	897,750	—
Edward J. Faneuil	(3)	n/a	897,750	—
Daphne H. Foster	(1)	5	33,086	—
Andrew P. Slifka	(1)	9	19,305	—
Andrew P. Slifka	(4)	14	160,585	—
Charles A. Rudinsky (5)	(1)	29	850,172	77,486

(1)Global Partners LP Pension Plan 

(2) Global Deferred Compensation Agreement

(3)Alliance Deferred Compensation Agreement

(4) Global Montello Group Corp. Pension Plan 

(5)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. 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 or disability. Certain employees are entitled to a supplemental benefit that vested over five years with 20% vesting on each December 31 beginning in 2010 and lasting through 2014. When an employee retires at age 65 or, if later, upon reaching five years' service, 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

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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.

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 during the current or next preceding year 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 or disability. 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 read “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 read “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 2015, 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
	Fees Earned	Grant Date Fair	All
	or Paid in	Value of Unit	Other	Total
Name	Cash ($)	Awards ($) (2)	Compensation	($)
Richard Slifka	70,000	—	—	70,000
Eric Slifka (1)	—	—	—	—
Andrew Slifka (1)	—	—	—	—
Kenneth I. Watchmaker	94,500	455,951	—	550,451
Robert J. McCool	87,000	444,797	—	531,797
David McKown	87,000	349,082	40,000	476,082

(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)As of December 31, 2015, our non-employee directors held the following aggregate number of unvested phantom units: Mr. Watchmaker (13,374), Mr. McCool (13,374) and Mr. McKown (13,374).

Employees of our general partner who also serve as directors do not receive additional compensation. In 2015, 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 2015, 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.

On December 31, 2014, the initial tranche of the June 27, 2013 awards vested and on January 15, 2015, Messrs. Watchmaker, McCool and McKown each received 2,715 common units of Global Partners LP.

On December 31, 2015, the second tranche of the June 27, 2013 awards vested and on January 12, 2016, Messrs. Watchmaker, McCool and McKown each received 2,715 common units of Global Partners LP.

On January 15, 2015, in respect of their excellent service during 2014, Messrs. Watchmaker and McCool received outright grants, respectively, of 1,504 and 1,204 common of Global Partners LP, and Mr. McKown received a cash award of $40,000.

On April 20, 2015, Messrs. Watchmaker and McCool each received an award of 3,553 phantom units and on September 18, 2015, Mr. McKown received an award of 3,553 phantom units. These phantom units vested on January 2, 2016. Messrs. Watchmaker and McCool each received these common units on January 12, 2016; Mr. McKown’s award was settled in cash on January 19, 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 February25, 2016 the beneficial ownership of common units representing limited partner interests in Global Partners LP held by certain beneficial owners of more than five percent (5%) of our common units, by each director and named executive officer of GlobalGPLLC, the general partner of Global PartnersLP and by all directors and executive officers of our general partner as a group:

		Percentage
	Common	of Common
	Units	Units
	Beneficially	Beneficially
Name of Beneficial Owner (1)	Owned	Owned
Richard Slifka (2)(3)(4)(5)(6)(7)(9)	5,579,582	16.4	%
Estate of Alfred A. Slifka  (2)(3)(4)(5)(6)(7)(8)	4,734,095	13.9	%
OppenheimerFunds Inc. (10)	3,263,947	9.6	%
Montello Oil Corporation (2)	2,348,078	6.9	%
Oppenheimer Steelpath MLP Income Fund (10)	1,955,665	5.8	%
Global Petroleum Corp. (3)	1,725,463	5.1	%
Eric Slifka (11)(12)	1,161,741	3.4	%
Larea Holdings LLC (11)	564,984	1.7	%
Global GP LLC (5)	481,613	1.4	%
Andrew Slifka (9)	496,372	1.5	%
Edward J. Faneuil	50,157	*
Charles A. Rudinsky	23,963	*
Mark Romaine	18,115	*
Daphne H. Foster	2,400	*
Robert J. McCool	21,414	*
Kenneth I. Watchmaker	23,064	*
David K. McKown	7,857	*
Larea Holdings II LLC (9)	282,492	*
Chelsea Terminal Limited Partnership (4)	120,356	*
Sandwich Terminal, L.L.C. (6)	8,475	*
All directors and executive officers as a group (10 persons)	7,384,665	21.7	%

*Less than 1%

(1) The address for each person or entity listed other than (i) OppenheimerFunds, Inc. and (ii) Oppenheimer Steelpath MLP Income Fund, is P.O. Box 9161, 800 South Street, Suite 500, Waltham, Massachusetts 02454‑9161.

(2) Richard Slifka and the estate of Alfred A. Slifka share voting and investment power with respect to and, therefore, may be deemed to beneficially own, the units owned by Montello Oil Corporation.

(3) Richard Slifka and the estate of Alfred A. Slifka share voting and investment power with respect to, and therefore may be deemed to beneficially own, the units owned by Global Petroleum Corp.

(4) Richard Slifka and the estate of Alfred A. 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.

(5) 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. Richard Slifka and the estate of Alfred A. Slifka control Global GP LLC, and thus may be deemed to beneficially own the units owned by Global GP LLC.

(6) Richard Slifka and the estate of Alfred A. 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.

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(7) Beneficially owned unit amounts for each of Richard Slifka and the estate of Alfred A. Slifka include the units owned by 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. Beneficially owned unit amounts for the estate of Alfred A. Slifka also include 50,110 units that are held by the estate of Alfred A. Slifka. Richard Slifka and the late Alfred A. Slifka are brothers.

(8) Alfred A. Slifka passed away on March 9, 2014. His estate is in probate and his beneficially owned interests set forth on the above table have not yet been settled.

(9) 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.

(10) According to a Schedule 13G/A filed on February 4, 2016, OppenheimerFunds, Inc. beneficially owned 3,263,947 common units, representing 9.6% of the common units then outstanding and Oppenheimer Steelpath MLP Income Fund beneficially owned 1,955,665 common units, representing 5.75% of the common units then outstanding. The address for OppenheimerFunds, Inc. is Two World Financial Center, 225 Liberty Street, New York, NY10281 and the address for Oppenheimer Steelpath MLP Income Fund is 6803 S. Tucson Way, Centennial, CO 80112-3924.

(11) 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 the late Alfred A. Slifka.

(12) 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, 2015:

			Number of securities
	Number of Securities		remaining available for
	to be issued	Weighted average	future issuance under
	upon exercise of	exercise price of	equity compensation plans
	outstanding options,	outstanding options,	(excluding securities
Plan Category	warrants and rights	warrants and rights	reflected in column (a))
	(a)	(b)	(c)
Equity compensation plans approved by security holders	584,942	—	3,680,093
Equity compensation plans not approved by security holders	—	—	—
Total	584,942	—	3,680,093

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

As of February25, 2016, affiliates of our general partner, including directors and executive officers of our general partner, owned 7,434,775 common units representing 21.9% of the limited partner interests in us. In addition, our general partner owns a 0.67% general partner interest in us.

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.

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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 99.33% 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 7,434,775 common units and 0.67% 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 48.67% 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 $13.8 million on their common units and $0.4 million on the 0.67% general partner interest.
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.
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 and Business Opportunity Agreement

We are a party to an omnibus agreement with Mr. Richard Slifka and our general partner that addresses the agreement of Mr. Richard Slifka not to compete with us and to cause his 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, 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.

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Noncompetition

Pursuant to the omnibus agreement and the business opportunity agreement, 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 of refined petroleum products, crude oil, renewable fuels (including ethanol and bio‑fuels), natural gas liquids (including ethane, butane, propane and condensates), natural gas, compressed natural gas and liquefied natural gas; (2) the storage of refined petroleum products and/or any of the other products identified in (1) in connection with any of the activities described in (1); (3) the sale of convenience store items and sundries and related food service; and (4) bunkering, unless the Chief Executive Officer and the board of directors approve such activity. Pursuant to the omnibus agreement, Richard Slifka’s noncompetition obligations survive for so long as 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 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. We believe the terms of this agreement are at least as favorable as could have been obtained from unaffiliated third parties. Under this agreement, we provide Global Petroleum Corp. with certain accounting, treasury, legal, information technology, human resources and financial operations support for which Global Petroleum Corp. pays or paid us an amount based upon the cost associated with the provision of such services. In addition, until February 1, 2015 (in connection with our acquisition of our petroleum products storage terminal located in Revere, Massachusetts from Global Petroleum Corp. and others), Global Petroleum Corp. provided us with certain terminal, environmental and operational support services, for which we paid a fee based on an agreed assessment of the cost associated with the provision of such services. With respect to the shared services agreement, we paid to Global Petroleum Corp. a total of $8,000, $96,000 and $96,000 for the years ended December 31, 2015, 2014 and 2013, respectively. The agreement with Global Petroleum Corp. was amended and restated on March 11, 2015 to remove the terminal, environmental and operational support services that had been provided to us. Under the amended and restated agreement, we will continue to provide Global Petroleum Corp. with certain tax, accounting, treasury and legal services at an agreed assessment of the cost associated with the provision of such services for an indefinite term, and any party may terminate its receipt of some or all of the services thereunder upon 90 days’ prior written notice. As of December 31, 2015, no notice of termination had been given under the agreement with Global Petroleum Corp. as then in effect.

We were party to a shared services agreement with AE Holdings until AE Holdings’ voluntary dissolution on July 10, 2015. We believe the terms of the AE Holdings agreement were at least as favorable as could have been obtained from unaffiliated third parties. Under this agreement, we provided AE Holdings with certain tax, accounting, treasury and legal support services for which AE Holdings paid us an aggregate of $15,000 per year, and either party had the ability to terminate its receipt of some or all of the services thereunder upon 90 days’ prior written notice.

Revere Terminal Acquisition from Global Petroleum Corp.

On January 14, 2015, we acquired the Revere terminal from Global Petroleum Corp. for a purchase price of approximately $23.7 million. Global Petroleum Corp. is owned by the Estate of Alfred A. Slifka and Richard Slifka. Pursuant to the purchase agreement entered into by both parties, we assumed all liabilities and obligations of Global Petroleum Corp. related to the terminal and the underlying real property, except for certain liabilities as set forth in the purchase agreement. We released Global Petroleum Corp. from and agreed to indemnify Global Petroleum Corp. from all known and unknown environmental liabilities relating to the terminal and underlying real property, provided that we will be responsible for the first remediation expenses arising from unknown conditions up to $1.5 million, in the

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aggregate, and then Global Petroleum Corp. will reimburse us for any remediation expenses in excess of $1.5 million up to $2.3 million, provided further that (i) Global Petroleum Corp. will have no obligation to reimburse us for expenses in excess of $750,000 in the aggregate, and (ii) Global Petroleum Corp.’s reimbursement obligations will survive for a period of three years following the closing of the acquisition. Any and all remediation expenses in excess of $2.3 million or incurred after the expiration of the three‑year survival period will be our responsibility.

In the event that we sell, within eight years of the closing of the acquisition, all or substantially all of the real property underlying the Revere terminal to a third party not affiliated with Global Petroleum Corp. or us and such third party does not intend to use the real property for petroleum‑related purposes, then we will pay Global Petroleum Corp. an amount equal to fifty percent of the net proceeds (as defined in the purchase agreement) received by us in connection with such sale.

Global Petroleum Corp. continued to provide terminalling services to us, and we continued to pay all amounts owed to Global Petroleum Corp., pursuant to the terms of the existing terminal storage rental and throughput agreement between Global Petroleum Corp. and us, until February 1, 2015

Throughput Agreement with Global Petroleum Corp.

We had an exclusive terminal storage rental and throughput agreement with Global Petroleum Corp. with respect to the Revere terminal in Revere, Massachusetts. The terminal storage rental and throughput agreement terminated on February 1, 2015 in connection with our acquisition of the Revere terminal from Global Petroleum Corp. We believe the terms of this agreement were at least as favorable as could have been obtained from unaffiliated third parties. We retained the title to all our products stored at this terminal. We paid a monthly fee to Global Petroleum Corp., which was 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 $0, $9.2 million and $9.1 million for the years ended December 31, 2015, 2014 and 2013, respectively.

Relationship of Management with Global Petroleum Corp. and AE Holdings Corp.

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.”

AE Holdings was 100% owned by members of the Slifka family until it was voluntarily dissolved effective July 10, 2015. Under a shared services agreement, Messrs. Eric Slifka, Faneuil and Rudinsky spent a portion of their time in 2015 providing services to AE Holdings until it was voluntarily dissolved. Please read “—Shared Services Agreements.”

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

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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 read 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 2015 and 2014 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 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.

Pre‑approved fees to Ernst & Young LLP for the fiscal year ended December31, 2015 and 2014 were as follows (in thousands):

	2015		2014
Audit Fees (1)	$	4,182	$	4,245
Audit—Related Fees		883		597
Tax Fees (2)		2,066		1,175
Total	$	7,131	$	6,017

(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, 2015 and 2014.  Fees for 2015 included an audit performed as part of our public offering and fees associated with our 2015 acquisitions.Fees for 2014 included an audit performed as part of our public offering.

(2) Tax fees included tax planning and tax return preparation.

120

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

Exhibits required to be filed by Item 601 of Registration S-K are set forth in the Exhibit Index accompanying this Annual Report and are incorporated herein by reference.

121

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.

	Global Partners LP
	By:	Global GP LLC,
		its general partner
Dated: February29, 2016		By:	/s/ Eric Slifka
			Eric Slifka
			President and Chief Executive Officer

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 February 29, 2016.

Signature	Title
/s/ Eric Slifka	President, Chief Executive Officer and Director
Eric Slifka	(Principal Executive Officer)
/s/ Daphne H. Foster	Chief Financial Officer
Daphne H. Foster	(Principal Financial Officer)
/s/ Charles A. Rudinsky	Executive Vice President and Chief Accounting Officer
Charles A. Rudinsky	(Principal Accounting Officer)
/s/ Andrew Slifka	Executive Vice President,
Andrew Slifka	President, Alliance Gasoline Division and Director
/s/ Richard Slifka	Chairman
Richard Slifka
/s/ David K. McKown	Director
David K. McKown
/s/ Robert J. McCool	Director
Robert J. McCool
/s/ Kenneth I. Watchmaker	Director
Kenneth I. Watchmaker

122

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, 2015 and 2014	F‑3
Consolidated Statements of Operations for the years ended December 31, 2015, 2014 and 2013	F‑4
Consolidated Statements of Comprehensive Income for the years ended December 31, 2015, 2014 and 2013	F‑5
Consolidated Statements of Cash Flows for the years ended December 31, 2015, 2014 and 2013	F‑6
Consolidated Statements of Partners’ Equity for the years ended December 31, 2015, 2014 and 2013	F‑7
Notes to Consolidated Financial Statements	F‑8

F-1

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, 2015 and 2014, and the related consolidated statements of operations, comprehensive income, partners’ equity, and cash flows for each of the three years in the period ended December 31, 2015. 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, 2015 and 2014, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2015, 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, 2015, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated February 29, 2016 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Boston, Massachusetts

February 29, 2016

F-2

GLOBAL PARTNERS LP

CONSOLIDATED BALANCE SHEETS

(In thousands, except unit data)

	December 31,
	2015		2014
Assets
Current assets:
Cash and cash equivalents	$	1,116	$	5,238
Accounts receivable, net (less allowance of $5,942 and $4,818 as of December 31, 2015 and 2014, respectively)		311,354		457,730
Accounts receivable—affiliates		2,578		3,903
Inventories		388,952		336,813
Brokerage margin deposits		31,327		17,198
Derivative assets		66,099		83,826
Prepaid expenses and other current assets		65,609		54,315
Total current assets		867,035		959,023
Property and equipment, net		1,242,683		825,051
Intangible assets, net		75,694		48,902
Goodwill		435,369		154,078
Other assets		42,894		43,763
Total assets	$	2,663,675	$	2,030,817
Liabilities and partners’ equity
Current liabilities:
Accounts payable	$	303,781	$	456,619
Working capital revolving credit facility—current portion		98,100		—
Line of credit		—		700
Environmental liabilities—current portion		5,350		3,101
Trustee taxes payable		95,264		105,744
Accrued expenses and other current liabilities		60,328		82,820
Derivative liabilities		31,911		58,507
Total current liabilities		594,734		707,491
Working capital revolving credit facility—less current portion		150,000		100,000
Revolving credit facility		269,000		133,800
Senior notes		656,564		360,096
Environmental liabilities—less current portion		67,883		34,462
Financing obligation		89,790		—
Deferred tax liabilities		84,836		12,958
Other long-term liabilities		56,884		45,854
Total liabilities		1,969,691		1,394,661
Commitments and contingencies (see Note 13)		—		—
Partners’ equity
Global Partners LP equity:
Common unitholders 33,995,563 units issued and 33,506,844 outstanding at December 31, 2015 and 30,995,563 units issued and 30,604,961 outstanding at December 31, 2014)		657,071		599,406
General partner interest (0.67% and 0.74% interest with 230,303 equivalent units outstanding at December 31, 2015 and 2014, respectively)		(1,188)		788
Accumulated other comprehensive loss		(8,094)		(13,252)
Total Global Partners LP equity		647,789		586,942
Noncontrolling interest		46,195		49,214
Total partners’ equity		693,984		636,156
Total liabilities and partners’ equity	$	2,663,675	$	2,030,817

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

F-3

GLOBAL PARTNERS LP

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per unit data)

	Year Ended December 31,
	2015		2014		2013
Sales	$	10,314,852	$	17,269,954	$	19,589,608
Cost of sales		9,717,183		16,725,167		19,185,052
Gross profit		597,669		544,787		404,556
Costs and operating expenses:
Selling, general and administrative expenses		177,043		153,961		115,491
Operating expenses		290,307		204,070		185,713
Amortization expense		13,499		18,867		19,216
Loss (gain) on sale and disposition of assets		2,097		2,182		(1,273)
Total costs and operating expenses		482,946		379,080		319,147
Operating income		114,723		165,707		85,409
Interest expense		(73,332)		(47,764)		(43,537)
Income before income tax benefit (expense)		41,391		117,943		41,872
Income tax benefit (expense)		1,873		(963)		(819)
Net income		43,264		116,980		41,053
Net loss (income) attributable to noncontrolling interest		299		(2,271)		1,562
Net income attributable to Global Partners LP		43,563		114,709		42,615
Less: General partner’s interest in net income, including incentive distribution rights		7,667		5,981		3,521
Limited partners’ interest in net income	$	35,896	$	108,728	$	39,094
Basic net income per limited partner unit	$	1.12	$	3.97	$	1.43
Diluted net income per limited partner unit	$	1.11	$	3.95	$	1.42
Basic weighted average limited partner units outstanding		32,178		27,420		27,329
Diluted weighted average limited partner units outstanding		32,323		27,502		27,560
Distributions per limited partner unit	$	2.74	$	2.53	$	2.34

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

F-4

GLOBAL PARTNERS LP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In thousands)

	Year Ended December 31,
	2015		2014		2013
Net income	$	43,264	$	116,980	$	41,053
Other comprehensive income (loss):
Change in fair value of cash flow hedges		4,047		3,151		3,930
Change in pension liability		1,111		(5,093)		4,430
Total other comprehensive income (loss)		5,158		(1,942)		8,360
Comprehensive income		48,422		115,038		49,413
Comprehensive loss (income) attributable to noncontrolling interest		299		(2,271)		1,562
Comprehensive income attributable to Global Partners LP	$	48,721	$	112,767	$	50,975

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

F-5

GLOBAL PARTNERS LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

	Year Ended December 31,
	2015		2014		2013
Cash flows from operating activities
Net income	$	43,264	$	116,980	$	41,053
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		115,851		86,364		77,134
Amortization of deferred financing fees		5,899		5,627		6,897
Amortization of leasehold interests		794		—		—
Amortization of senior notes discount		1,089		559		368
Bad debt expense		1,172		1,700		4,145
Unit—based compensation expense		4,208		3,485		1,806
Write—off of financing fees		—		1,626		—
Loss (gain) on sale and disposition of assets		2,097		2,182		(1,273)
Deferred income taxes		(3,624)		(11)		336
Changes in operating assets and liabilities, excluding net assets acquired:
Accounts receivable		154,716		226,962		8,524
Accounts receivable—affiliate		1,325		(2,499)		(97)
Inventories		(32,648)		235,993		61,992
Broker margin deposits		(14,129)		4,594		32,934
Prepaid expenses, all other current assets and other assets		12,526		(49,020)		11,226
Accounts payable		(172,318)		(324,500)		18,667
Trustee taxes payable		(15,648)		25,528		(11,278)
Change in derivatives		(8,869)		(17,509)		5,778
Accrued expenses, all other current liabilities and other long—term liabilities		(33,199)		26,841		(3,065)
Net cash provided by operating activities		62,506		344,902		255,147
Cash flows from investing activities
Acquisitions		(561,170)		—		(185,262)
Capital expenditures		(92,925)		(95,114)		(67,132)
Proceeds from sale of property and equipment		4,331		4,021		9,187
Net cash used in investing activities		(649,764)		(91,093)		(243,207)
Cash flows from financing activities
Proceeds from issuance of common units, net		109,305		137,844		—
Borrowings from (payments on) working capital revolving credit facility		148,100		(227,000)		(97,500)
Borrowings from (payments on) revolving credit facility		135,200		(300,900)		12,700
Proceeds from senior notes, net of discount		295,338		258,903		147,900
Repayment of senior notes		—		(40,244)		—
Proceeds from issuance of term loan		—		—		115,000
Repayment of term loan		—		—		(115,000)
(Payments on) borrowings from line of credit		(700)		(3,000)		3,700
Repurchase of common units		(3,892)		(8,632)		(4,590)
Repurchased units withheld for tax obligations		—		—		(2,086)
Noncontrolling interest capital contribution		2,560		8,200		1,425
Distribution to noncontrolling interest		(5,280)		(9,200)		(2,920)
Distributions to partners		(97,495)		(73,759)		(67,329)
Net cash provided by (used in) financing activities		583,136		(257,788)		(8,700)
Cash and cash equivalents
(Decrease) increase in cash and cash equivalents		(4,122)		(3,979)		3,240
Cash and cash equivalents at beginning of year		5,238		9,217		5,977
Cash and cash equivalents at end of year	$	1,116	$	5,238	$	9,217
Supplemental information
Cash paid during the period for interest	$	59,764	$	31,554	$	34,179
Cash paid during the period for income taxes	$	2,772	$	757	$	273
Non-cash exchange of 6.25% senior notes due 2022	$	—	$	110,000	$	—

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

F-6

GLOBAL PARTNERS LP

CONSOLIDATED STATEMENTS OF PARTNERS’ EQUITY

(In thousands)

						Accumulated
			General		Other				Total
	Common		Partner		Comprehensive		Noncontrolling		Partners’
	Unitholders		Interest		Loss		Interest		Equity
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
Unit-based compensation		1,806		—		—		—		1,806
Distributions to partners		(64,190)		(3,352)		—		—		(67,542)
Repurchase of common units		(4,590)		—		—		—		(4,590)
Dividends on repurchased units		213		—		—		—		213
Repurchased units withheld for tax obligation		(2,086)		—		—		—		(2,086)
Balance at December 31,  2013		426,785		(238)		(11,310)		47,943		463,180
Issuance of common units		137,844		—		—		—		137,844
Net income		108,728		5,981		—		2,271		116,980
Noncontrolling interest capital contribution		—		—		—		8,200		8,200
Distribution to noncontrolling interest		—		—		—		(9,200)		(9,200)
Other comprehensive loss		—		—		(1,942)		—		(1,942)
Unit-based compensation		3,485		—		—		—		3,485
Distributions to partners		(69,333)		(4,955)		—		—		(74,288)
Repurchase of common units		(8,632)		—		—		—		(8,632)
Dividends on repurchased units		529		—		—		—		529
Balance at December 31,  2014		599,406		788		(13,252)		49,214		636,156
Issuance of common units		109,305		—		—		—		109,305
Net income (loss)		35,896		7,667		—		(299)		43,264
Noncontrolling interest capital contribution		—		—		—		2,560		2,560
Distribution to noncontrolling interest		—		—		—		(5,280)		(5,280)
Other comprehensive loss		—		—		5,158		—		5,158
Unit-based compensation		4,208		—		—		—		4,208
Distributions to partners		(88,944)		(9,643)		—		—		(98,587)
Repurchase of common units		(3,892)		—		—		—		(3,892)
Dividends on repurchased units		1,092		—		—		—		1,092
Balance at December 31,  2015	$	657,071	$	(1,188)	$	(8,094)	$	46,195	$	693,984

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

F-7

GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1. Organization and Basis of Presentation

Organization

Global Partners LP (the “Partnership”) is a midstream logistics and marketing master limited partnership formed in March 2005 engaged in the purchasing, selling, storing and logistics of transporting petroleum and related products, including domestic and Canadian crude oil, gasoline and gasoline blendstocks (such as ethanol), distillates (such as home heating oil, diesel and kerosene), residual oil, renewable fuels, natural gas and propane. The Partnership also receives revenue from convenience store sales and gasoline station rental income. 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 owns transload and storage terminals in North Dakota and Oregon that extend its origin-to-destination capabilities from the mid-continent region of the United States and Canada to the East and West Coasts. The Partnership is one of the largest distributors of gasoline, distillates, residual oil and renewable fuels to wholesalers, retailers and commercial customers in the New England states and New York. As of December 31, 2015, the Partnership had a portfolio of 1,509 owned, leased and/or supplied gasoline stations, including 281 directly operated convenience stores, in the Northeast, Maryland and Virginia.

On January 7, 2015, the Partnership acquired, through one of its wholly owned subsidiaries, Global Montello Group Corp. (“GMG”), 100% of the equity interests in Warren Equities, Inc. (“Warren”) from The Warren Alpert Foundation. On January 14, 2015, the Partnership acquired the Revere terminal (the “Revere Terminal”) located in Boston Harbor in Revere, Massachusetts from Global Petroleum Corp. (“GPC”) and related entities. On June 1, 2015, the Partnership acquired, through one of its wholly owned subsidiaries, Alliance Energy LLC (“Alliance”), retail gasoline stations and dealer supply contracts from Capitol Petroleum Group (“Capitol”). See Note 3.

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 most of its gasoline station and convenience store employees and certain union personnel who are employed by GMG.

The General Partner, which holds a 0.67% general partner interest in the Partnership (reduced from 0.74% following the Partnership’s public offering of common units discussed in Note 15), is owned by affiliates of the Slifka family. As of December 31, 2015, affiliates of the General Partner, including its directors and executive officers and their affiliates, owned 7,434,775 common units, representing a 21.9% limited partner interest.

Ownership by affiliates of the General Partner decreased by approximately 4,305,522 common units (from 37.9% at December 31, 2014 to 21.9% at December 31, 2015), primarily as a result of the liquidation of AE Holdings Corp. (“AE Holdings”) in March 2015 and a subsequent intrafamily sale by the Estate of AlfredA. Slifka to a Slifka family member. Immediately prior to such liquidation, the directors and executive officers of the General Partner were deemed to beneficially own all 5,850,000 common units that were then owned by AE Holdings. Upon the liquidation of AE Holdings, the 5,850,000 common units were distributed to the stockholders of AE Holdings. An aggregate 1,956,234 common units were sold by certain of the stockholders of AE Holdings in a public offering in March 2015. As of December 31, 2015, approximately 2,306,960 common units of the 5,850,000 common units were held by certain of the directors and executive officers of the General Partner, and the remaining 1,586,806 common units were held by unaffiliated members of the Slifka family.

F-8

GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 2. Summary of Significant Accounting Policies

Basis of Consolidation and Presentation

On January 7, 2015, the Partnership acquired 100% of the equity interests in Warren, on January 14, 2015, the Partnership acquired the Revere Terminal and on June 1, 2015, the Partnership acquired Capitol. The financial results of Warren and the Revere Terminal for the year ended December 31, 2015 and of Capitol for the seven months ended December 31, 2015 are included in the accompanying statement of operations for the year ended December 31, 2015.

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”). 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 operations for the year ended December 31, 2013.

See Note 3, “Business Combinations,” for additional information on the Partnership’s acquisitions. The accompanying consolidated financial statements as of December 31, 2015 and 2014 and for the years ended December 31, 2015, 2014 and 2013 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 statements 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 statements 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 sheets and statements of operations.

Reclassifications

Certain prior year amounts in the consolidated financial statements have been reclassified 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) fair value of derivative instruments, (iii) accruals and contingent liabilities, (iv) allowance for doubtful accounts, (v) Level 3

F-9

GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

valuations for crude oil and propane forward purchase and sales contracts, and (vi) assumptions used to evaluate goodwill, property and equipment and intangibles for impairment and environmental and asset retirement obligations provisions and cost of sales accrual. Although the Partnership believes these estimates are reasonable, actual results could differ from these estimates.

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 results 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, 2015 and 2014, substantially all of the Partnership’s accounts receivable classified as current assets were within payment terms.

Inventories

The Partnership hedges substantially all of its petroleum and ethanol inventory using a variety of instruments, primarily exchange-traded futures contracts. These futures contracts are entered into when inventory is purchased and are either designated as fair value hedges against the inventory on a specific barrel basis for inventories qualifying for fair value hedge accounting or not designated and maintained as economic hedges against certain inventory of the Partnership on a specific barrel basis. Changes in fair value of these futures contracts, as well as the offsetting change in fair value on the hedged inventory, is recognized in earnings as an increase or decrease in cost of sales. All hedged inventory designated in a fair value hedge relationship is valued using the lower of cost, as determined by specific identification, or market, as determined at the product level. All petroleum and ethanol inventory not designated in a fair value hedging relationship is carried at the lower of historical cost, on a first-in, first-out basis, or market.

Convenience store inventory and Renewable Identification Numbers (“RINs”) inventory are carried at the lower of historical cost or market.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

	2015		2014
Distillates: home heating oil, diesel and kerosene	$	156,411	$	163,679
Gasoline		62,467		82,080
Gasoline blendstocks		32,542		33,760
Crude oil		102,253		20,769
Residual oil		12,895		20,602
Propane and other		1,469		5,123
Renewable identification numbers (RINs)		803		2,057
Convenience store inventory		20,112		8,743
Total	$	388,952	$	336,813

In addition to its own inventory, the Partnership has exchange agreements for petroleum products and ethanol with unrelated third‑party suppliers, whereby it may draw inventory from these other suppliers (see Revenue Recognition) and suppliers may draw inventory from the Partnership. Positive exchange balances are accounted for as accounts receivable and amounted to $3.4 million and $3.9 million at December 31, 2015 and 2014, respectively. Negative exchange balances are accounted for as accounts payable and amounted to $12.1 million and $16.5 million at December 31, 2015 and 2014, 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 related to the Partnership’s terminal assets and gasoline stations is charged to cost of sales and all other depreciation is charged to selling, general and administrative expenses. Depreciation is charged 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:

Gasoline station buildings, improvements and storage tanks	15-25	years
Buildings, docks, terminal facilities and improvements	5-25	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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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.

No material impairment charges were required in 2015, 2014 and 2013. However, at December 31, 2015, the Partnership had a $39.4 million remaining net book value of long‑lived assets used at its crude oil transloading terminals in North Dakota. The long‑term recoverability of these assets might be adversely impacted by any prolonged decline in crude oil commodity prices or crude oil differentials. Over the long‑term, if these market conditions remain, this may become an indicator of the potential impairment of these North Dakota assets in the future. The Partnership will monitor the pricing environment and the related impact this may have on the North Dakota operating and cash flows and whether this would constitute an impairment indicator.

The Partnership evaluates its assets for impairment on a quarterly basis.

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. At December 31, 2015, goodwill recorded in the accompanying consolidated balance sheet aggregated $435.4 million, of which $121.7 million relates to the Wholesale segment and $313.7 million relates to the GDSO segment.

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 process of testing goodwill for impairment involves numerous judgments, assumptions and estimates made by management which inherently reflect a high degree of uncertainty. 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. In the quantitative assessment, the fair value of each reporting unit is determined and compared to the book value of the reporting unit. If the fair value of the reporting unit is less than the book value, including goodwill, then the recorded goodwill is impaired to its implied fair value with a charge to operations. The Partnership calculates the fair value of each reporting unit using a combination of discounted cash flows and market comparables.

Key assumptions included in the development of the discounted cash flow value for each reporting unit include:

Future commodity volumes and margins.  The discounted cash flows are based on a five-year forecast with an estimate of terminal value. In general, the reporting units’ fair values are most sensitive to volume and gross margin assumptions. In particular, the Wholesale segment’s cash flows are impacted by the crude oil market, given the Partnership’s 2013 investment in transloading terminals in North Dakota and Oregon. The significant decline in the price of crude oil and tight crude oil differentials negatively impacted the Partnership’s fiscal 2015 results. The Partnership expects low crude oil prices and tight differentials to continue for a period of time, which will negatively impact the Partnership’s 2016 performance with recovery expected in 2017. As a result of these market conditions, there is increased uncertainty and sensitivity relating to the Partnership’s future cash flow projections within its crude oil business on which the Wholesale reporting unit’s goodwill impairment analysis relies. If market conditions, and therefore the Partnership’s performance, are worse than its projections, the Partnership may record impairment charges in the future. Actual results may not be consistent with these

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

judgments, assumptions and estimates, and goodwill impairment charges may be required in future periods. This could have an adverse impact on the Partnership’s financial position and results of operations.

Discount rate commensurate with the risks involved.  The Partnership applies a discount rate to its expected cash flows based on a variety of factors, including market and economic conditions, operational risk, regulatory risk and political risk. A higher discount rate decreases the net present value of cash flows.

Future capital requirements.  The Partnership’s estimates of future capital requirements are based upon a combination of authorized spending and internal forecasts.

On October 1, 2015, the Partnership completed its quantitative assessments for both the Wholesale and GDSO reporting units, and no impairment indicator was identified for either reporting unit. The declining crude oil prices, changes in certain market conditions, and decline in the Partnership’s common unit price, collectively caused the Partnership to reassess its goodwill for impairment as of December31, 2015 for the Wholesale reporting unit. Based on the results of this assessment, the Partnership concluded that step-two of the quantitative assessment was not necessary and no impairment was required. 

The fair values of the Partnership’s reporting units are based on underlying assumptions that represent the Partnership’s best estimates. Many of the factors used in assessing fair value are outside of the control of management. A further sustained decline in commodity prices may cause the Partnership to reassess its long-lived assets and goodwill for impairment, and could result in future non-cash impairment charges as a result of such impairment assessments. If the Partnership is required to perform step-two in the future for the Wholesale reporting unit, up to $121.7million of goodwill assigned to this reporting unit could be written off in the period of such impairment assessment.

During 2014, the Partnership completed step-one quantitative assessments for both the Wholesale and GDSO reporting units and no impairment was identified for either reporting unit. Due to declining oil prices and other market indicators at December 31, 2014, the Partnership updated the assessment of the recovery of goodwill through December 31, 2014 and concluded there was no impairment. During 2013, the Partnership completed a qualitative assessment for the GDSO reporting unit and no impairment was required. During 2013, a quantitative assessment was completed for the Wholesale reporting unit, and no impairment was required.

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.

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 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 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

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

regulations, there are 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 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. The liability for an asset retirement obligation is recognized on a discounted basis in the year in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying cost of the asset. The Partnership had approximately $7.8 million and $3.8 million in total asset retirement obligations at December 31, 2015 and 2014, respectively, which are included in other long‑term liabilities in the accompanying balance sheets. Approximately $1.8 million and $0.9 million of these obligations at December 31, 2015 were assumed in the 2015 acquisitions of Warren and Capitol, respectively.

Leases

The Partnership had a throughput agreement with GPC with respect to its terminal in Revere, Massachusetts. This agreement was accounted for as an operating lease in 2014 and 2013. On January 14, 2015, the Partnership acquired the Revere terminal from GPC (see Note 3). The Partnership also has lease agreements with the Port of St. Helens for land and for access rights to a rail spur and dock located at its Oregon facility. The Partnership also has terminal and throughput lease arrangements with various unrelated oil terminals and third parties, certain of which arrangements have minimum usage requirements. In addition, the Partnership leases certain gasoline stations from third parties under long‑term arrangements with various expiration dates. The Partnership’s has  a long‑term lease agreement with Getty Realty which enables the Partnership to supply and operate certain Getty Realty gasoline station sites.

The Partnership has future commitments, principally for office space and computer equipment, under the terms of operating lease arrangements. The Partnership also leases railcars and barges through various lease arrangements with various expiration dates. The Partnership has rental income from gasoline stations and cobranding arrangements and lease income from space leased to several unrelated third parties at several of our terminals. Additionally, the Partnership has capital leases for other computer equipment and leasehold improvements.

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

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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.

Product 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. The Partnership recognizes net exchange differentials due from exchange partners in sales upon delivery of product to an exchange partner.

The Partnership collects trustee taxes, which consist of various pass through taxes collected 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, crude oil and ethanol 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. 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 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.

On July 1, 2015 the Partnership commenced business in Canada through its wholly owned Canadian subsidiary, Global Partners Energy Canada,ULC (“GPEC”). GPEC predominantly consists of sourcing crude oil and other petroleum based products for sale to the Partnership and customers in Canada. GPEC is a taxable entity for Canadian

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

corporate income and branch taxes. In its first year of operations, GPEC realized a pre-tax loss generating a net operating loss that might be used to offset future taxable income when GPEC operates at a profit. 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 the accounting guidance regarding income taxes. Based upon projections of future taxable income, limited capital assets and market conditions, the Partnership has provided a full valuation allowance against the GPEC deferred tax asset. See Note5.

Foreign Currency Transactions

Gains/(losses) realized from transactions denominated in foreign currencies are included in cost of sales in the consolidated statements of operations and totaled ($714,000),  ($25,000) and $162,000 for the years ended December 31, 2015, 2014 and 2013, respectively.

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 in investment‑grade securities. 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 and directly operated convenience stores are located in the Northeast, Maryland and Virginia.

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 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 that the Partnership distributes. Therefore, the Partnership’s volumes in gasoline 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 volumes are generally higher during the first and fourth quarters of the calendar year. These factors may result in fluctuations in the Partnership’s quarterly operating results.

The following table presents the Partnership’s product sales and other revenues as a percentage of the consolidated sales for the years ended December 31:

	2015		2014		2013
Gasoline sales: gasoline and gasoline blendstocks (such as ethanol)	59	%	60	%	58	%
Crude oil sales and crude oil logistics revenue	12	%	14	%	18	%
Distillates (home heating oil, diesel and kerosene), residual oil, natural gas and propane sales	25	%	25	%	23	%
Convenience store sales, rental income and sundry sales	4	%	1	%	1	%
Total	100	%	100	%	100	%

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

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

The Partnership principally uses derivative instruments, which include regulated exchange-traded futures and options contracts (collectively, “exchange-traded derivatives”) and physical and financial forwards and over-the counter (“OTC”) swaps (collectively, “OTC derivatives”), to reduce its exposure to unfavorable changes in commodity market prices and interest rates. The Partnership uses these exchange-traded and OTC derivatives to hedge commodity price risk associated with its inventory and undelivered forward commodity purchases and sales (“physical forward contracts”) and uses interest rate swap instruments to reduce its exposure to fluctuations in interest rates associated with the Partnership’s credit facilities. The Partnership accounts for derivative transactions in accordance with ASC 815, “Derivatives and Hedging,” and recognizes derivatives instruments as either assets or liabilities in the consolidated balance sheet and measures those instruments at fair value. The changes in fair value of the derivative transactions are presented currently in earnings, unless specific hedge accounting criteria are met.

The fair value of exchange-traded derivative transactions reflects amounts that would be received from or paid to the Partnership’s brokers upon liquidation of these contracts. The fair value of these exchange-traded derivative transactions are presented on a net basis, offset by the cash balances on deposit with the Partnership’s brokers, presented as brokerage margin deposits in the consolidated balance sheets. The fair value of OTC derivative transactions reflects amounts that would be received from or paid to a third party upon liquidation of these contracts under current market conditions. The fair value of these OTC derivative transactions is presented on a gross basis as derivative assets or derivative liabilities in the consolidated balance sheets, unless a legal right of offset exists. The presentation of the change in fair value of the Partnership’s exchange-traded derivatives and OTC derivative transactions depends on the intended use of the derivative and the resulting designation.

Derivatives Accounted for as Hedges – The Partnership utilizes fair value hedges and cash flow hedges to hedge commodity price risk and interest rate risk.

Fair Value Hedges

Derivatives designated as fair value hedges are used to hedge price risk in commodity inventories and principally include exchange-traded futures contracts that are entered into in the ordinary course of business. For a derivative instrument designated as a fair value hedge, the gain or loss is recognized in earnings in the period of change together with the offsetting change in fair value on the hedged item of the risk being hedged. Gains and losses related to fair value hedges are recognized in the consolidated statement of operations through cost of sales. These futures contracts are settled on a daily basis by the Partnership through brokerage margin accounts.

Cash Flow Hedges

Derivatives designated as cash flow hedges are used to hedge interest rate risk from fluctuations in interest rates and may include various interest rate derivative instruments entered into with major financial institutions. For a derivative instrument being designated as a cash flow hedge, the effective portion of the derivative gain or loss is initially reported as a component of other comprehensive income (loss) and subsequently reclassified into the consolidated statement of operations through interest expense in the same period that the hedged exposure affects earnings. The ineffective portion is recognized in the consolidated statement of operations immediately.

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Derivatives Not Accounted for as Hedges – The Partnership utilizes petroleum and ethanol commodity contracts, natural gas commodity contracts and foreign currency derivatives to hedge price and currency risk in certain commodity inventories and physical forward contracts.

Petroleum and Ethanol Commodity Contracts

The Partnership uses exchange-traded derivative contracts to hedge price risk in certain commodity inventories which do not qualify for fair value hedge accounting or are not designated by the Partnership as fair value hedges. Additionally, the Partnership uses exchange-traded derivative contracts, and occasionally financial forward and OTC swap agreements, to hedge commodity price exposure associated with its physical forward contracts which are not designated by the Partnership as cash flow hedges. These physical forward contracts, to the extent they meet the definition of a derivative, are considered OTC physical forwards and are reflected as derivative assets or derivative liabilities in the consolidated balance sheet. The related exchange-traded derivative contracts (and financial forward and OTC swaps, if applicable) are also reflected as brokerage margin deposits (and derivative assets or derivative liabilities, if applicable) in the consolidated balance sheet, thereby creating an economic hedge. Changes in fair value of these derivative instruments are recognized in the consolidated statement of operations through cost of sales. These exchange-traded derivatives 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 commodity product purchase and sale activities, it may experience net unbalanced positions for short periods of time as a result of variances in daily purchases and 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, the Partnership is aided by maintaining a constant presence in the marketplace. The Partnership also engages in a controlled trading program for up to an aggregate of 250,000 barrels of commodity products at any one point in time. Changes in fair value of these derivative instruments are recognized in the consolidated statement of operations through cost of sales.

Natural Gas Commodity Contracts

The Partnership uses physical forward purchase contracts to hedge price risk associated with the marketing and selling of natural gas to third-party users. These physical forward purchase commitments for natural gas are typically executed when the Partnership enters into physical forward sale commitments of product for physical delivery. These physical forward contracts, to the extent they meet the definition of a derivative, are reflected as derivative assets and derivative liabilities in the consolidated balance sheet. Changes in fair value of the forward purchase and sale commitments are recognized in the consolidated statement of operations through cost of sales.

Foreign Currency Contracts

The Partnership uses forward foreign currency contracts to hedge certain foreign denominated (Canadian) commodity product purchases. These forward foreign currency contracts are not designated by the Partnership as hedges and are reflected as prepaid expenses and other current assets or accrued expenses and other current liabilities in the consolidated balance sheets. Changes in fair values of these forward foreign currency contracts are reflected in cost of sales.

Margin Deposits

All of the Partnership’s exchange-traded derivative contracts (designated and not designated) are transacted through clearing brokers. The Partnership deposits initial margin with the clearing brokers, along with variation margin, which is paid or received on a daily basis, based upon the changes in fair value of open futures contracts and settlement of closed futures contracts. Cash balances on deposit with clearing brokers and open equity are presented on a net basis within brokerage margin deposits in the consolidated balance sheets.

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Please See Note 4 “Derivative Financial Instruments,” for additional information.

Fair Value Measurements

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Partnership utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. The Partnership primarily applies the market approach for recurring fair value measurements and endeavors to utilize the best available information. Accordingly, the Partnership utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The Partnership is able to classify fair value balances based on the observability of those inputs. The fair value hierarchy that prioritizes the inputs used to measure fair value, giving the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). At each balance sheet reporting date, the Partnership categorizes its financial assets and liabilities using the three levels of the fair value hierarchy defined as follows:

Level 1—Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as the Partnership’s exchange-traded derivative instruments and pension plan assets.

Level 2—Quoted prices in active markets are not available; however, pricing inputs are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Level 2 primarily consists of non-exchange-traded derivatives such as OTC derivatives.

Level 3—Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. Level 3 includes certain OTC forward derivative instruments related to crude oil and propane.

Please see Note18, “Fair Value Measurements,” for additional information.

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 unitholders, or limited partners’ interest, and to the General Partner’s general partner interest.

Common units outstanding as reported in the accompanying consolidated financial statements at December31, 2015 and 2014 excluded  403,922 and 390,602 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).

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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, 2015
			Limited		General
			Partner		Partner
Numerator:	Total		Interest		Interest		IDRs
Net income attributable to Global Partners LP (1)	$	43,563	$	35,896	$	7,667	$	—
Declared distribution	$	92,059	$	84,055	$	582	$	7,422
Assumed allocation of undistributed net income		(48,496)		(48,159)		(337)		—
Assumed allocation of net income	$	43,563	$	35,896	$	245	$	7,422
Denominator:
Basic weighted average limited partner units outstanding				32,178
Dilutive effect of phantom units				145
Diluted weighted average limited partner units outstanding				32,323
Basic net income per limited partner unit			$	1.12
Diluted net income per limited partner unit			$	1.11

	Year Ended December 31, 2014
			Limited		General
			Partner		Partner
Numerator:	Total		Interest		Interest		IDRs
Net income attributable to Global Partners LP (2)	$	114,709	$	108,728	$	5,981	$	—
Declared distribution	$	78,771	$	73,143	$	593	$	5,035
Assumed allocation of undistributed net income		35,938		35,585		353		—
Assumed allocation of net income	$	114,709	$	108,728	$	946	$	5,035
Denominator:
Basic weighted average limited partner units outstanding				27,420
Dilutive effect of phantom units				82
Diluted weighted average limited partner units outstanding				27,502
Basic net income per limited partner unit			$	3.97
Diluted net income per limited partner unit			$	3.95

(1) As a result of the June 2015 issuance of 3,000,000 common units (see Note15), the general partner interest was reduced to 0.67% from 0.74% and was, based on a weighted average, approximately 0.70% for the year ended December31, 2015.

(2) As a result of the December 2014 issuance of 3,565,000 common units (see Note15), the general partner interest was reduced to 0.74% from 0.83%. The issuance of these common units did not have a material impact on the Partnership’s basic or diluted net income per limited partner unit for the year ended December31, 2014.

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	Year Ended December 31, 2013
			Limited		General
			Partner		Partner
Numerator:	Total		Interest		Interest		IDRs
Net income attributable to Global Partners LP	$	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

The board of directors of the General Partner declared the following quarterly cash distributions for the four quarters ended December 31, 2015:

	Per Unit Cash			Distribution Declared for the
Cash Distribution Declaration Date	Distribution Declared			Quarterly Period Ended
April 22, 2015	$	0.6800	(1)	March 31, 2015
July 22, 2015	$	0.6925	(1)	June 30, 2015
October 21, 2015	$	0.6975	(1)	September 30, 2015
January 28, 2016	$	0.4625		December 31, 2015

(1) This declared cash distribution resulted in an incentive distribution to the General Partner, as the holder of the IDRs, and enable the Partnership to exceed its third 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 November 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2015-17, “Income Taxes: Balance Sheet Classification of Deferred Taxes.” This standard simplifies the presentation of deferred income taxes and provides presentation requirements to classify deferred tax assets and liabilities as non-current in a classified statement of financial position. The standard is effective for fiscal years beginning after December5, 2016, including interim periods within those fiscal years. The Partnership early adopted this standard as of December31, 2015 and applied the guidance retrospectively. As a result, as of December31, 2014, current deferred taxes included in prepaid expenses and other current assets decreased by $1.1million and long-term deferred income taxes increased by $1.1million. The adoption of this standard did not have a material impact on the Partnership’s consolidated financial statements. See Note 5.

In April 2015, the FASB issued ASU No. 2015-03, “Interest-Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs.” This standard requires debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying value of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by this standard. The amendments in this standard are effective retrospectively for fiscal years, and interim periods within those years, beginning after December 15, 2015. The Partnership adopted this standard as of December31, 2015 and, as a result, reclassed unamortized debt issuance costs of approximately $6.9 million from other assets and $1.1 million from prepaid expenses and other current assets, a total of $8.0 million, to a reduction of senior notes in the accompanying balance

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

sheet as of December31, 2014. The adoption of this standard did not have a material impact on the Partnership’s consolidated financial statements. See Note 8.

Accounting Standards or Updates Not Yet Effective

In February 2016, the FASB issued ASU No. 2016-02, “Leases.” This standard amends the existing accounting standards for lease accounting, including requiring lessees to recognize most leases on their balance sheets and making targeted changes to lessor accounting. This standard is effective beginning in the first quarter of 2019. Early adoption of this standard is permitted. The standard requires a modified retrospective transition approach for all leases existing at, or entered into after, the date of initial application, with an option to use certain transition relief. The Partnership is assessing the impact this standard will have on its consolidated financial statements.

In January 2016, the FASB issued ASU No. 2016-01, “Financial Instruments - Recognition and Measurement of Financial Assets and Financial Liabilities”.  This standard revises the classification and measurement of investments in certain equity investments and the presentation of certain fair value changes for certain financial liabilities measured at fair value. This standard also requires the change in fair value of many equity investments to be recognized in net income. This standard is effective for interim and annual periods beginning after December15, 2017, with early adoption permitted. The adoption of this standard is not expected to have a material impact on the Partnership’s consolidated financial statements.

In September 2015, the FASB issued ASU No. 2015-16, “Business Combinations: Simplifying the Accounting for Measurement-Period Adjustments.” This standard eliminates the requirement that an acquirer in a business combination account for measurement-period adjustments retrospectively. Instead, acquirers must recognize measurement-period adjustments during the period in which they determine the amounts, including the effect on earnings of any amounts they would have recorded in previous periods if the accounting had been completed at the acquisition date. The acquirer still must disclose the amounts and reasons for adjustments to the provisional amounts. The acquirer also must disclose, by line item, the amount of the adjustment reflected in the current-period income statement that would have been recognized in previous periods if the adjustment to provisional amounts had been recognized as of the acquisition date. Alternatively, an acquirer may present those amounts separately on the face of the income statement. This new standard is effective for fiscal years beginning after December 15, 2015, including interim periods within those fiscal years. Early adoption is permitted. The adoption of this standard is not expected to have a material impact on the Partnership’s consolidated financial statements.

In July 2015, the FASB issued ASU No. 2015-11, “Simplifying the Measurement of Inventory,” which requires an entity to measure inventory within the scope of the amendment at the lower of cost and net realizable value. Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. The new standard is effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years. The Partnership is assessing the impact this standard will have on its consolidated financial statements.

In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers,” that introduces a new five-step revenue recognition model in which an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This standard also requires disclosures sufficient to enable users to understand the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers, including qualitative and quantitative disclosures about contracts with customers, significant judgments and changes in judgments, and assets recognized from the costs to obtain or fulfill a contract. In July 2015, the FASB approved a one-year deferral of the effective date of the standard to fiscal periods beginning after December 15, 2017. The Partnership is evaluating the new guidance to determine the impact it will have on its consolidated financial statements.

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 3. Business Combinations

2015 Acquisitions

Warren Equities, Inc.—On January7, 2015, the Partnership acquired, through GMG, 100% of the equity interests in Warren, one of the largest independent marketers of petroleum products in the Northeast, from The Warren Alpert Foundation. The acquisition included 147 company-owned Xtra Mart convenience stores and related fuel operations, 53 commission agent locations and fuel supply rights for approximately 330 dealers. The acquired properties are located in the Northeast, Maryland and Virginia. The purchase price, inclusive of post-closing adjustments, was approximately $381.8 million, including working capital. The acquisition was funded with borrowings under the Partnership’s credit facility and with proceeds from its December 2014 public offering of 3,565,000 common units.

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 Warren subsequent to the acquisition date.

The following table presents the final 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	$	9,511
Inventory		19,144
Prepaid expenses and other current assets		11,038
Property and equipment		255,148
Intangibles		38,360
Other non-current assets		16,595
Total identifiable assets purchased		349,796
Liabilities assumed:
Accounts payable		(23,067)
Environmental liabilities		(36,467)
Taxes payable		(5,168)
Accrued expenses		(4,462)
Long-term deferred taxes		(75,501)
Other non-current liabilities		(9,739)
Total liabilities assumed		(154,404)
Net identifiable assets acquired		195,392
Goodwill		186,437
Net assets acquired	$	381,829

The fair value of loan receivables purchased of $25.0 million was estimated by management based on the receivable’s payment terms, assumptions of current interest rates and collectability and is included in prepaid expenses and other current assets and other non-current assets. The gross contractual amount for these loan receivables is $29.1 million, of which the Partnership estimates $2.4 million is not collectible.

The liability for environmental matters has been estimated by the Partnership with the assistance from third-party environmental engineers (see Note 9). Based on an analysis, the estimated provision for environmental matters related to Warren is $36.5 million.

The long-term deferred tax liabilities of $75.5 million is primarily related to temporary differences associated

F-23

GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

with the fair value allocations of property and equipment and intangible assets, which are not deductible for tax purposes, net of acquired environmental liabilities and other deductible accrued liabilities.

The Partnership engaged a third-party valuation firm to assist in the valuation of Warren’s property and equipment, intangible assets consisting of supply contracts and favorable leasehold interests, and unfavorable leasehold interests. The Partnership’s third-party valuation firm considered the income, market, and cost approaches in estimating the fair value of the property and equipment, supply contracts and leasehold interests. The income, market, and cost approaches were used to value the property and equipment based on the underlying asset class components of the property and equipment. The excess earnings method under the income approach was used to value the supply contracts. The income approach was used to value the favorable and unfavorable leasehold interests.

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 Gasoline Distribution and Station Operations (“GDSO”) reporting unit. The goodwill recognized is attributable primarily to expected synergies and growth opportunities for the Partnership. For federal income tax purposes, the acquisition of Warren was deemed to be a stock purchase and, therefore, any recorded goodwill is not expected to be tax deductible. In accordance with the stock purchase agreement between the Partnership and Warren, the Partnership is ultimately not responsible for federal income tax obligations for the interim period, June 1, 2014 to January 6, 2015 (Warren’s fiscal year end was May 31). Any tax obligations will be funded by the selling shareholders. Any tax refund will be remitted to the selling shareholders. Included in accounts receivable and accounts payable at December 31, 2015 is an estimated refund of $8.3 million to be paid to the selling shareholder of Warren. In addition, reflected in accounts payable is a $1.8 million payable representing planned utilization of net operating losses, the benefit of which was an assumed liability of the Partnership.

The fair values of the remaining Warren assets and liabilities noted above approximate their carrying values at January 7, 2015.

As part of the purchase price allocation, identifiable intangible assets include $37.6 million of supply contracts and $0.8 million of favorable leasehold interests that are being amortized over seven to ten years and five years, respectively. The weighted average life over which these acquired intangibles are being amortized is approximately ten and five years, respectively. The supply contracts are subject to renewals, and assumptions related to the renewals have been included in the determination of the value of the supply contracts at the date of acquisition. The Partnership determines the renewal assumptions used based on management’s assumptions of future events, including customer demand, customer attrition rates, contract renewal length and market overall conditions. The supply contracts had a weighted average term of approximately five years prior to their next renewal. Amortization expense related to the supply contracts amounted to $3.9 million for the year ended December 31, 2015.

The estimated remaining amortization expense for the supply contracts acquired in connection with the acquisition for each of the five succeeding years and thereafter is as follows (in thousands):

2016	$	3,899
2017		3,899
2018		3,899
2019		3,899
2020		3,899
Thereafter		13,931
Total	$	33,426

F-24

GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Amortization related to the favorable leasehold interests was immaterialfor the year ended December 31, 2015. The estimated remaining amortization for favorable leasehold interests acquired in connection with the acquisition for each of the four succeeding years is as follows (in thousands):

2016	$	152
2017		152
2018		152
2019		152
Total	$	608

In connection with the acquisition of Warren, the Partnership incurred acquisition costs of $5.4 million and $1.7 million for the years ended December 31, 2015 and 2014, respectively, which are included in selling, general and administrative expenses in the accompanying consolidated statements of operations. Additionally, in January 2015 and subsequent to the acquisition date, the Partnership recorded a restructuring charge of approximately $2.3 million, which is included in selling, general and administrative expenses in the accompanying consolidated statement of operations for the year ended December 31, 2015. This charge, which was principally for redundant and/or eliminated positions as a result of the acquisition, was not part of the purchase price allocation. The $2.3 million restructuring charge was paid during the year ended December 31, 2015.

The acquisition of Warren complements the Partnership’s existing retail presence in the Northeast and expands its footprint into the adjacent Mid-Atlantic region. The Warren operations have been integrated into the Partnership’s GDSO reporting segment.

Revere Terminal—On January 14, 2015, through the Partnership’s wholly owned subsidiary, Global Companies, the Partnership acquired the Revere Terminal located in Boston Harbor in Revere, Massachusetts from GPC, a privately held affiliate of the Partnership, and related entities for a purchase price of $23.7 million. The acquisition includes contingent consideration which would be payable under specific circumstances involving a subsequent sale of the property during the next eight years. The contingent consideration was estimated to be $0 as of the acquisition date and as of December 31, 2015 as the Partnership concluded that the treatment of the contingent consideration as a non-fair value measure is appropriate and that, as of December 31, 2015, the sale of the terminal for non-petroleum use within the next eight years is not probable. The Partnership financed the transaction with borrowings under its revolving credit facility. In connection with the Revere Terminal transaction, the pre-existing terminal storage rental and throughput agreement between the Partnership and GPC was terminated.

The acquisition was accounted for using the purchase method of accounting in accordance with the FASB’s guidance regarding business combinations. As the acquisition transitioned the Revere Terminal from a formerly leased facility to an owned facility, the transaction did not have a material impact on the Partnership’s consolidated financial statements.

F-25

GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table presents the final 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:
Property and equipment	$	28,481
Total identifiable assets purchased		28,481
Liabilities assumed:
Environmental liabilities		(3,074)
Other non-current liabilities		(1,757)
Total liabilities assumed		(4,831)
Net assets acquired	$	23,650

The liability for environmental matters has been estimated by the Partnership with the assistance from third-party environmental engineers (see Note 9). Based on an analysis, the estimated provision for environmental matters related to the Revere Terminal is $3.1 million.

The Partnership engaged a third-party valuation firm to assist in the valuation of the Revere Terminal’s property and equipment. The Partnership’s third-party valuation firm considered the income, market and cost approaches in estimating the fair value of the property and equipment. The market and cost approaches were principally used to value the property and equipment based on the underlying asset class components of the property and equipment. The fair values of the remaining Revere Terminal liabilities noted above approximate their carrying values at January14, 2015.

Capitol Petroleum Group—On June 1, 2015, the Partnership acquired 97 primarily Mobil and Exxon branded owned or leased retail gasoline stations and seven dealer supply contracts in New York City and Prince George’s County, Maryland, along with certain related supply and franchise agreements and third-party leases and other assets associated with the operations from Liberty Petroleum Realty,LLC, East River Petroleum Realty,LLC, Big Apple Petroleum Realty,LLC, White Oak Petroleum,LLC, Anacostia Realty,LLC, Mount Vernon Petroleum Realty,LLC and DAG Realty,LLC (collectively, “Capitol Petroleum Group”). The purchase price was approximately $155.7 million. The acquisition was financed with borrowings under the Partnership’s revolving 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 Capitol subsequent to the acquisition date.

F-26

GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table presents the final 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:
Inventory	$	346
Property and equipment		149,583
Intangibles		3,000
Other non-current assets		57
Total identifiable assets purchased		152,986
Liabilities assumed:
Financing obligation		(89,613)
Environmental liabilities		(300)
Other non-current liabilities		(2,236)
Total liabilities assumed		(92,149)
Net identifiable assets acquired		60,837
Goodwill		94,854
Net assets acquired	$	155,691

The liability for environmental matters was developed by management based on their estimates, assumptions and acquisition history (see Note 9). Based on an analysis, the estimated provision for environmental matters related to Capitol is $0.3 million.

The Partnership engaged a third-party valuation firm to assist in the valuation of Capitol’s property and equipment, intangible assets consisting of supply contracts and favorable leasehold interests and unfavorable leasehold interests. The Partnership’s third-party valuation firm considered the income, market and cost approaches in estimating the fair value of the property and equipment, supply contracts and leasehold interests. The market and cost approaches were used to value the property and equipment based on the underlying asset class components of the property and equipment. The excess earnings method under the income approach was used to value the supply contracts. The income approach was used to value the favorable and unfavorable leasehold interests.

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 GDSO reporting unit. The goodwill recognized is attributable primarily to the expansion of the Partnership’s presence in active markets in the East Coast in which the Partnership can leverage its existing operations and dealer relationships without significant incremental expense to grow the business. The transaction also positions the Partnership to expand through tuck-in acquisitions as well as new-to-industry sites. The goodwill is tax deductible. The operations of Capitol have been integrated into the Partnership’s GDSO reporting segment.

The estimated fair value of property and equipment of $149.6 million includes $60.0 million of owned property and equipment and $89.6 million of certain properties previously sold by Capitol within two sale-leaseback transactions that did not meet the criteria for sale accounting. As a result of not meeting the criteria for sale accounting, the property and equipment sold and leased back by Capitol has not been derecognized and, in purchase accounting, the estimated fair value of property and equipment associated with these sites has been recognized within property and equipment. Depreciation expense associated with these sale-leaseback properties amounted to $2.1 million for the year ended December 31, 2015.

The financing obligation of $89.6 million recognized is attributable to the two sale-leaseback transactions discussed above that did not meet the criteria for sale accounting and, as a result, were accounted for as financing

F-27

GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

arrangements. These lease agreements mature in May 2028 and September 2029, and the fair value assigned to the financing obligation was estimated by management based on the remaining payments attributable to the lease agreements over their terms and is equal to the estimated fair value of property and equipment associated with these sites. Over the course of the lease agreements, the lease rental payments will be classified as interest expense on the financing obligation and the pay-down of the financing obligation as opposed to operating expense. Interest expense and lease rental payments associated with the financing obligation for these sale-leaseback properties amounted to $5.6 million and $5.4 million for the year ended December 31, 2015, respectively. The financing obligation balance outstanding at December 31, 2015 was $89.8million.

The fair values of the remaining Capitol assets and liabilities noted above approximate their carrying values at June1, 2015.

As part of the purchase price allocation, identifiable intangible assets include $0.8million of supply contracts and $2.2million of favorable leasehold interests that are being amortized over seven and two years, respectively. The weighted average life over which these acquired intangibles are being amortized is approximately seven and two years, respectively. The supply contracts are subject to renewals, and assumptions related to the renewals have been included in the determination of the value of the supply contracts at the date of acquisition. The Partnership determines the renewal assumptions used based on management’s assumptions of future events, including customer demand, customer attrition rates, contract renewal length and market overall conditions. The supply contracts had a weighted average term of approximately one year prior to their next renewal. Amortization expense related to the supply contracts was immaterial for the year ended December 31, 2015.

The estimated remaining amortization expense for the supply contracts acquired in connection with the acquisition for each of the five succeeding years and thereafter is as follows (in thousands):

2016	$	114
2017		114
2018		114
2019		114
2020		114
Thereafter		163
Total	$	733

Amortization of favorable leasehold interests was $0.6 million for the year ended December31, 2015. The estimated remaining amortization for favorable leasehold interests acquired in connection with the acquisition for each of the two succeeding years is as follows (in thousands):

2016	$	1,100
2017		458
Total	$	1,558

In connection with the acquisition of Capitol, the Partnership incurred acquisition costs of approximately $3.5 million which are included in selling, general and administrative expenses in the accompanying consolidated statement of operations for the year ended December 31, 2015.

Supplemental Pro Forma Information—Revenues and net income not included in the Partnership’s consolidated operating results for Warren from January 1, 2015 through January 7, 2015, the acquisition date, were immaterial. Accordingly, the supplemental pro forma information for the year ended December 31, 2015 is consistent with the amounts reported in the accompanying consolidated statement of operations for the year ended December 31,

F-28

GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

2015. As the acquisition transitioned the Revere Terminal from a formerly leased facility to an owned facility, the transaction did not have a material impact on the Partnership’s consolidated financial statements.

The following unaudited pro forma information for 2014 presents the consolidated results of operations of the Partnership as if the acquisition of Warren occurred at the beginning of 2014, with pro forma adjustments to give effect to intercompany sales and certain other adjustments. The following unaudited pro forma information for 2015 and 2014 presents the consolidated results of operations of the Partnership as if the acquisition of Capitol occurred at the beginning of each period presented, with pro forma adjustments to give effect to certain adjustments (in thousands, except per unit data):

	Year Ended December 31,
	2015		2014
Sales	$	10,540,275	$	19,303,900
Net income attributable to Global Partners LP	$	47,555	$	85,058
Net income per limited partner unit, basic	$	1.24	$	2.89
Net income per limited partner unit, diluted	$	1.23	$	2.88

Pro forma information for Warren for the year ended December 31, 2014 was based on unaudited revenues and net income. Pro forma information for Capitol for the period from January 1, 2015 through May 31, 2015 and for the year ended December 31, 2014 was estimated based on unaudited annual revenues and net income.

Warren’s revenues and net income included in the Partnership’s consolidated operating results from January 7, 2015, the acquisition date, through the year ended December 31, 2015 were $1.1 billion and $23.0 million, respectively. Capitol’s revenues and net income included in the Partnership’s consolidated operating results from June 1, 2015, the acquisition date, through the year ended December 31, 2015 were $0.2 billion and $6.2 million, respectively.

F-29

GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 4. Derivative Financial Instruments

The following table summarizes the notional values related to the Partnership’s derivative instruments outstanding at December 31, 2015:

	Units (1)		Unit of Measure
Exchange-Traded Derivatives
Long		37,785	Thousands of barrels
Short		(44,135)	Thousands of barrels
OTC Derivatives (Petroleum/Ethanol)
Long		7,840	Thousands of barrels
Short		(8,073)	Thousands of barrels
OTC Derivatives (Natural Gas)
Long		9,919	Thousands of decatherms
Short		(9,939)	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)	$	0.7	Millions of Canadian dollars
	$	0.5	Millions of U.S. dollars

(1) Number of open positions and gross notional values do not measure the Partnership’s risk of loss, quantify risk or represent assets or liabilities of the Partnership, but rather indicate the relative size of the derivative instruments and are used in the calculation of the amounts to be exchanged between counterparties upon settlements.

(2) All‑in forward rate Canadian dollars $1.3828 to USD $1.00.

Fair Value Hedges

The Partnership’s fair value hedges include exchange-traded futures contracts and OTC derivative contracts that are hedges against inventory with specific futures contracts matched to specific barrels. The change in fair value of these futures contracts and the change in fair value of the underlying inventory generally provide an offset to each other in the consolidated statement of operations.

The following table presents the gains and losses from the Partnership’s derivative instruments involved in fair value hedging relationships recognized in the consolidated statements of operations for the years ended December 31 (in thousands):

	Statement of Gain (Loss)
	Recognized in Income on	December 31,
	Derivatives	2015		2014		2013
Derivatives in fair value hedging relationship
Exchange-traded futures contracts and OTC derivative contracts for petroleum commodity products	Cost of sales	$	151,344	$	139,473	$	(18,231)
Hedged items in fair value hedge relationship
Physical inventory	Cost of sales	$	(158,987)	$	(141,699)	$	17,949

F-30

GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Cash Flow Hedges

The Partnership’s cash flow hedges currently include interest rate swaps and an interest rate cap that are hedges of variability in forecasted interest payments due to changes in the interest rate on LIBOR-based borrowings, a summary of which includes the following designations:

· 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%.  

In the aggregate, these hedging instruments have historically been effective in hedging the variability in interest payments due to changes in the one month LIBOR swap curve or rate with respect to $300.0 million of one month LIBOR based borrowings on the credit facility.

In June 2014 and as a result of the issuance of the Partnership’s $375.0 million aggregate principal amount of its 6.25% senior notes due 2022 (see Note 8), the Partnership determined that maintaining an excess of $300.0 million in principal of outstanding floating-rate debt was no longer probable. Therefore, the Partnership elected to de-designate its interest rate cap and discontinued the related hedge accounting for this instrument. Accordingly, at December 31, 2015, the Partnership had in place two interest rate swap agreements which are hedging $200.0 million of variable rate debt, both of which continue to be accounted for as cash flow hedges. The interest rate cap is not currently in a hedging relationship. Accordingly, all changes in fair value of this instrument subsequent to the date of de-designation are recorded in the consolidated statement of operations through interest expense.

F-31

GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table presents the amount of gains and losses from the Partnership’s derivative instruments designated in cash flow hedging relationships recognized in the consolidated statements of operations and partners’ equity for the years ended December 31 (in thousands):

							Location of Gain (Loss)
	Amount of Gain (Loss)						Reclassified from	Amount of Gain (Loss)
	Recognized in						Accumulated Other	Reclassified from Other
	Other Comprehensive						Comprehensive Income into	Comprehensive Income into
Derivatives Designated in	Income on Derivatives (Effective Portion)						Income (Effective Portion)	Income (Effective Portion)
Cash Flow Hedging Relationship	2015		2014		2013			2015		2014		2013
Interest rate collar	$	—	$	—	$	1,868	Interest expense	$	—	$	—	$	—
Interest rate swaps		3,353		2,766		2,071	Interest expense		—		—		—
Interest rate cap (1)		(17)		(8)		(9)	Interest expense		—		—		—
Total	$	3,336	$	2,758	$	3,930		$	—	$	—	$	—

(1) The interest rate cap was de-designated as a cash flow hedge in June 2014. Prepaid interest rate caplet amounts recognized in accumulated other comprehensive income up until the date of de-designation have been frozen in partner’s equity as of the de-designation date and are being amortized to income through the tenor of the interest rate cap instrument. The change in the fair value of the interest rate cap following de-designation is reflected in earnings and was immaterial for the years ended December 31, 2015 and 2014. As of December 31, 2015, the remaining unamortized prepaid interest rate caplets were $0.3 million and will be amortized over the remaining life for the interest rate cap which expires in April 2016.

The amount of gain (loss) recognized in income as ineffectiveness for derivatives designated in cash flow hedging relationships was $0 for the years ended December 31, 2015, 2014 and 2013.

Derivatives Not Accounted for as Hedges

The following table presents the gains and losses from the Partnership’s derivative instruments not involved in a hedging relationship recognized in the consolidated statements of operations for the years ended December 31 (in thousands):

	Statement of Gain (Loss)
Derivatives not designated as	Recognized in	December 31,
hedging instruments	Income on Derivatives	2015		2014		2013
Commodity contracts	Cost of sales	$	5,930	$	18,894	$	11,819
Forward foreign currency contracts	Cost of sales		191		25		(162)
Total		$	6,121	$	18,919	$	11,657

Commodity Contracts and Other Derivative Activity

The Partnership’s commodity contract derivatives and other derivative activity include: (i) exchange-traded derivative contracts that are hedges against inventory and either do not qualify for hedge accounting or are not designated in a hedge accounting relationship, (ii) exchange-traded derivative contracts used to economically hedge physical forward contracts, (iii) financial forward and OTC swap agreements used to economically hedge physical forward contracts and (iv) the derivative instruments under the Partnership’s controlled trading program. The Partnership does not take the normal purchase and sale exemption available under ASC 815 for its physical forward contracts.

F-32

GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table presents the fair value of each classification of the Partnership’s derivative instruments and its location in the consolidated balance sheets at December 31, 2015 and 2014 (in thousands):

		December 31, 2015
		Derivatives		Derivatives Not
		Designated as		Designated as
		Hedging		Hedging
	Balance Sheet Location	Instruments		Instruments		Total
Asset Derivatives:
Exchange-traded derivative contracts	Broker margin deposits	$	83,645	$	11,722	$	95,367
Forward derivative contracts (1)	Derivative assets		—		66,099		66,099
Forward foreign currency contracts	Other assets		—		10		10
Interest rate cap contract	Other assets		—		—		—
Total asset derivatives		$	83,645	$	77,831	$	161,476
Liability Derivatives:
Forward derivative contracts (1)	Derivative liabilities	$	—	$	31,911	$	31,911
Interest rate swap contracts	Other long-term liabilities		—		3,343		3,343
Total liability derivatives		$	—	$	35,254	$	35,254

		December 31, 2014
		Derivatives		Derivatives Not
		Designated as		Designated as
		Hedging		Hedging
	Balance Sheet Location	Instruments		Instruments		Total
Asset Derivatives:
Exchange-traded derivative contracts	Broker margin deposits	$	30,600	$	90,890	$	121,490
Forward derivative contracts (1)	Derivative assets		—		83,826		83,826
Forward foreign currency contracts	Other assets		—		9		9
Interest rate cap contract	Other assets		—		17		17
Total asset derivatives		$	30,600	$	174,742	$	205,342
Liability Derivatives:
Forward derivative contracts (1)	Derivative liabilities	$	—	$	58,507	$	58,507
Interest rate swap contracts	Other long-term liabilities		—		6,696		6,696
Total liability derivatives		$	—	$	65,203	$	65,203

(1) Forward derivative contracts include the Partnership’s petroleum and ethanol physical and financial forwards and OTC swaps.

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 to the Partnership’s exchange-traded and OTC derivative contracts, but the Partnership has no current reason to expect any material nonperformance by any of these counterparties. Exchange-traded derivative 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”), Chicago Mercantile Exchange (“CME”) and IntercontinentalExchange (“ICE”) derivative transactions and the right of offset exists with these financial institutions under master netting agreements. Accordingly, the fair value of the Partnership’s exchange-traded derivative instruments is presented on a net basis in the consolidated balance sheets.

F-33

GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Exposure on OTC derivatives 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:

	2015		2014		2013
Federal statutory income tax rate	35.0	%	34.0	%	34.0	%
State income tax rate, net of federal tax benefit	0.7	%	0.7	%	0.9	%
Foreign income tax	0.6	%	0.1	%	—	%
Partnership income not subject to tax	(40.8)	%	(34.0)	%	(32.9)	%
Effective income tax rate	(4.5)	%	0.8	%	2.0	%

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

	2015		2014		2013
Current:
Federal	$	110	$	(91)	$	(59)
State		1,388		877		542
Foreign		253		188		—
Total current		1,751		974		483
Deferred:
Federal		(1,298)		948		442
State		(2,326)		(959)		(106)
Total deferred		(3,624)		(11)		336
Total	$	(1,873)	$	963	$	819

F-34

GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

	2015		2014
Deferred Income Tax Assets
Accounts receivable allowances	$	2,097	$	413
Environmental liability		17,814		4,211
Asset retirement obligation		3,132		1,490
Intangible assets		—		114
Deferred rent		40		—
UNICAP		747		663
Other		4,477		44
Federal net operating loss carryforwards		13,930		14,203
State net operating loss carryforwards		2,684		1,537
Federal tax credit carryforward		761		13
Total deferred tax assets, gross		45,682		22,688
Valuation allowance		(975)		—
Total deferred tax assets, net	$	44,707	$	22,688
Deferred Income Tax Liabilities
Property and equipment	$	(104,798)	$	(30,041)
Land		(11,527)		(5,605)
Intangible assets		(13,218)		—
Total deferred tax liabilities	$	(129,543)	$	(35,646)
Net deferred tax assets (liabilities)	$	(84,836)	$	(12,958)

The increase in net deferred tax assets and liabilities during 2015 is primarily due to the January 2015 acquisition of Warren which, for federal income tax purposes, was deemed to be a stock purchase and, therefore, the historical tax basis is the assets acquired and liabilities assumed carried over to the Partnership upon acquisition. New deferred tax assets and liabilities were created based on the comparison of the historical tax basis to the fair value book basis.

At December 31, 2015, GMG had federal and state net operating loss carryforwards of approximately $38.5 million and $54.6 million, respectively, which will begin to expire in 2030 and 2016, 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.

At December31, 2015, the Partnership had $73.3million of net deferred tax liabilities (consisting of the $84.8million total net deferred tax liability less the $11.5million deferred tax liability relating to landdiscussed below) relating to property and equipment, net operating loss carryforwards, tax credit carryforwards and other temporary differences, certain of which are available to reduce income taxes in future years. The Partnership recognizes deferred tax assets to the extent that the recoverability of these assets satisfy the “more likely than not” criteria in accordance with the FASB’s guidance regarding income taxes. 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 and reversal of existing taxable temporary differences, that a portion of these assets will not be realized in a future period. The valuation allowance increased by approximately $1.0million as of December31, 2015, primarily due to state net operating loss carryforwards.

F-35

GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

At December 31, 2015, the Partnership also had an$11.5 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 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):

	2015		2014		2013
Income before income tax expense	$	41,391	$	117,943	$	41,872
Non—taxable income		(48,861)		(117,465)		(41,640)
Income subject to income tax expense	$	(7,470)	$	478	$	232

The Partnership made approximately $2.8 million, $0.7 million and $0.3 million in income tax payments during 2015, 2014 and 2013, 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 2012.

At December 31, 2015 and 2014, the Partnership had gross-tax effected unrecognized tax benefits of $0.1 million and $0, respectively, of which none would favorably impact the effective tax rate if recognized. The FASB’s accounting guidance for income taxes clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements by prescribing a minimum recognition threshold and measurement of a tax position taken or expected to be taken in a tax return. 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, 2015 (tax years ended December 31, 2015, 2014 and 2013). 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. The Partnership classifies interest and penalties related to income taxes as components of its provision for income taxes, and the amount of interest and penalties recorded in the accompanying balance sheets as of December31, 2015 and 2014 and in the accompanying statements of operations for the years ended December31, 2015, 2014 and 2013 were immaterial. The Partnership does not expect any material changes in the amount of unrecognized tax benefits over the next twelve months.

Note 6. Property and Equipment

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

	2015		2014
Buildings and improvements	$	992,917	$	667,172
Land		450,045		288,929
Fixtures and equipment		40,946		26,577
Construction in process		67,080		66,119
Capitalized internal use software		18,852		7,530
Total property and equipment		1,569,840		1,056,327
Less accumulated depreciation		327,157		231,276
Total	$	1,242,683	$	825,051

F-36

GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The increase of approximately $417.6 million in total property and equipment at December 31, 2015 was primarily due to the Partnership’s 2015 acquisitions of Warren, Capitol and the Revere Terminal, which contributed to $433.2 million of acquired property and equipment (see Note 3).

At December31, 2015 and 2014, construction in process included $30.5 million related to the Partnership’s ethanol plant acquired from Cascade Kelly in 2013. The Partnership has begun to take steps to utilize this location. This measure is substantially related to cleaning of tanks and associated infrastructure and is expected to be completed in the third quarter of 2016. Therefore, as of December31, 2015 and 2014, the recorded value of the ethanol plant is included in construction in process. After the plant has been placed into service, depreciation will commence. Construction in process in 2015 also included $23.1million in costs associated with the Partnership’s terminals,  which primarily included dock expansion, tank construction projects, rail expansion and improvements, various upgrades at certain terminals and investments in information technology, and $13.5million in costs related to the Partnership’s gasoline stations. At December 31, 2014, construction also included $30.8million in costs associated with the Partnership’s crude oil activities, primarily tank construction projects, rail expansion and improvements, various upgrades at certain terminals and investments in information technology, and $4.8million in costs related to the Partnership’s gasoline stations.

As part of continuing operations, the Partnership may periodically divest certain gasoline stations. The gain or loss on the sale, representing cash proceeds less net book value of assets at disposition, is recorded in (loss)  gain on sale and disposition of assets in the accompanying consolidated statements of operations and amounted to ($2.1 million),  ($2.2 million) and $1.3 million for the years ended December 31, 2015, 2014 and 2013, respectively. Additionally, in conjunction with the periodic divestiture of gasoline stations, the Partnership may classify certain gasoline station assets as held-for-sale. The Partnership classified $7.4 million and $3.3 million at December31, 2015 and 2014, respectively, as assets held-for-sale which are included in property and equipment in the accompanying balance sheets.

Depreciation

Depreciation expense allocated to cost of sales was approximately $94.8 million, $61.4 million and $55.6 million for the years ended December 31, 2015, 2014 and 2013, respectively. The increase in 2015 compared to 2014 and 2013 was due primarily to the January 2015 acquisition of Warren and the June 2015 acquisition of Capitol.

Depreciation expense allocated to selling, general and administrative expenses was approximately $7.5 million, $6.1 million and $2.3 million for the years ended December 31, 2015, 2014 and 2013, respectively.The increase in 2015 compared to 2014 and 2013 was due primarily to the January 2015 acquisition of Warren and the June 2015 acquisition of Capitol. The increase in 2014 compared to 2013 was due primarily to a full year of depreciation related to the Partnership’s February 2013 acquisitions of Basin Transload and Cascade Kelly.

There were no fully depreciated assets written off for the years ended December 31, 2015 and 2014.

F-37

GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 7. Goodwill and Intangible Assets

There were no changes to the Partnership’s goodwill during the year ended December 31, 2014. The following table presents changes in goodwill by segment during the year ended December 31, 2015 (in thousands):

	Goodwill Allocated to
	Wholesale		GDSO
	Reporting		Reporting
	Unit		Unit		Total
Balance at December 31, 2014	$	121,752	$	32,326	$	154,078
Acquisition of Warren		—		186,437		186,437
Acquisition of Capitol		—		94,854		94,854
Balance at December 31, 2015	$	121,752	$	313,617	$	435,369

Intangible assets consisted of the following (in thousands):

	Gross				Net
	Carrying		Accumulated		Intangible		Amortization
	Amount		Amortization		Assets		Period
At December 31, 2015
Intangible assets subject to amortization:
Terminalling services	$	26,365	$	(11,087)	$	15,278	20 years
Customer relationships		43,986		(39,691)		4,295	2-15 years
Supply contracts		77,771		(24,412)		53,359	5-15 years
Favorable leasehold interests		2,960		(794)		2,166	2-5 years
Brand incentive program		1,445		(1,117)		328	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		(511)		268	20 years
Total intangible assets	$	155,694	$	(80,000)	$	75,694
At December 31, 2014
Intangible assets subject to amortization:
Terminalling services	$	26,365	$	(9,752)	$	16,613	20 years
Customer relationships		43,986		(35,996)		7,990	2-15 years
Supply contracts		39,646		(16,345)		23,301	5-15 years
Brand incentive program		1,445		(879)		566	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	$	(65,707)	$	48,902

The increase in total intangible assets in 2015 compared to 2014 was due primarily to the January 2015 acquisition of Warren and, to a lesser extent, the June 2015 acquisition of Capitol. The aggregate amortization expense was approximately $13.5 million, $18.9 million and $19.2 million for the years ended December 31, 2015, 2014 and 2013, respectively. The decrease in amortization expense in 2015 compared to 2014 and 2013 was due to intangible assets that became fully amortized during 2015.

F-38

GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

2016	$	11,011
2017		10,025
2018		9,477
2019		9,477
2020		9,176
Thereafter		26,528
Total intangible assets	$	75,694

Note 8. Debt

Credit Agreement

As of December 31, 2015, certain subsidiaries of the Partnership, as borrowers, and the Partnership and certain of its subsidiaries, as guarantors, had a $1.775 billion senior secured credit facility (the “Credit Agreement”).On February 24, 2016, the Partnership and certain of its subsidiaries entered into the fifth amendment to the Credit Agreement. This amendment reflects the Partnership’s voluntary election to reduce the maximum aggregate amount available under the Credit Agreement to $1.475 billion (see “—Amendment to Credit Agreement” below). The Credit Agreement will mature on April 30, 2018.

As of December 31, 2015, 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 $775.0 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. 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.

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.

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 Loan Parties are permitted to sell or transfer any account receivable to an AR Buyer only pursuant to the provisions provided 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 minimis.

F-39

GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Availability under the working capital revolving credit facility is subject to a borrowing base which is redetermined from time to time 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.

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). 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).

The average balance under the working capital revolving credit facility was $234.1 million and $208.4 million for the years ended December 31, 2015 and 2014, respectively, and the average balance under the revolving credit facility was $382.2 million and $353.2 million for the years ended December 31, 2015 and 2014, respectively.  The average interest rates for the Credit Agreement were 3.6%,3.7% and 4.2% for the years ended December 31, 2015, 2014 and 2013, respectively.

As of December 31, 2015, the Partnership had two interest rate swaps, both of which were used to hedge the variability in interest payments under the Credit Agreement due to changes in LIBOR rates. See Note 2 and Note 4 for additional information on these cash flow hedges. Additionally, the Partnership has an interest rate cap that is hedging variable interest. The cap is not designated for accounting purposes.

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 current liability and a portion as a long-term liability. The portion classified as a long-term liability represents the amounts expected to be outstanding during the entire year based on an analysis of historical borrowings under the working capital revolving credit facility, the seasonality of borrowings, forecasted future working capital requirements and forward product curves, and because the Partnership has a multi-year, long-term commitment from its bank group. Accordingly, at December 31, 2015, the Partnership estimated working capital revolving credit facility borrowings will equal or exceed $150.0million over the next twelve months and, therefore, classified $98.1million as the current portion at December 31, 2015, representing the amount the Partnership expects to pay down over the next twelve months. The long-term portion of the working capital revolving credit facility was $150.0 million and $100.0 million at December 31, 2015 and 2014, respectively, and the current portion was $98.1 million and $0, at December 31, 2015 and 2014, respectively. The increase in total borrowings under the working capital revolving credit facility of $148.1 million from December 31, 2014 was primarily due to cash used in operating assets and liabilities during the year. Inventory increased due to higher volume stored, and accounts payable and receivables decreased as a result of declining prices during the year.

As of December 31, 2015, the Partnership had total borrowings outstanding under the Credit Agreement of $517.1 million, including $269.0 million outstanding on the revolving credit facility. In addition, the Partnership had outstanding letters of credit of $63.7 million. Subject to borrowing base limitations, the total remaining availability for borrowings and letters of credit was $1.2 billion and $1.4 billion at December 31, 2015 and 2014, respectively.

F-40

GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 subsidiaries with the exception of Basin Transload.

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 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, 2015. 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).

Amendment to Credit Agreement

On February 24, 2016, the Partnership and certain of its subsidiaries entered into the fifth amendment to the Credit Agreement (the “Fifth Amendment”). The Fifth Amendment includes certain modifications to the Credit Agreement to (i) amend the definition of “Total Combined Leverage Ratio” to permit for an increased maximum ratio of 5.50:1.00 through the first quarter of 2017 and 5.00:1.00 thereafter, (ii) amend the definition of “Applicable Revolver Rate” to align the pricing levels with the amended Total Combined Leverage Ratio maximum thresholds, (iii) increase the permitted level of asset Dispositions (as it is defined in the Credit Agreement) from $100.0 million to $150.0 million, and (iv) incorporate acknowledgement of and consent to the applicability of European Union Bank Recovery and Resolution Directive bail-in legislation. 

Unrelated to the foregoing modifications, the Fifth Amendment also reflects the Partnership’s voluntary election to reduce its working capital revolving credit facility from $1.0 billion to $900.0 million and its revolving credit facility from $775.0 million to $575.0 million, for a total available commitment of $1.475 billion.

6.25% Senior Notes

On June 19, 2014, the Partnership and GLP Finance Corp. (“GLP Finance” and, together with the Partnership, the “Issuers”) entered into a Purchase Agreement (the “Purchase Agreement”) with the Initial Purchasers (as defined therein) (the “Initial Purchasers”) pursuant to which the Issuers agreed to sell $375.0 million aggregate principal amount of the Issuers’ 6.25% senior notes due 2022 (the “6.25% Notes”) to the Initial Purchasers in a private placement exempt from the registration requirements under the Securities Act of 1933, as amended (the “Securities Act”). The 6.25% Notes were resold by the Initial Purchasers to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to persons outside the United States pursuant to Regulation S under the Securities Act.

The Purchase Agreement contained customary representations and warranties of the parties and indemnification and contribution provisions under which the Issuers and the subsidiary guarantors, on one hand, and the Initial Purchasers, on the other, agreed to indemnify each other against certain liabilities, including liabilities under the Securities Act. In addition, the Purchase Agreement required the execution of a registration rights agreement, described below, relating to the 6.25% Notes. Closing of the offering occurred on June 24, 2014.

F-41

GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Indenture

In connection with the private placement of the 6.25% Notes on June 24, 2014, the Issuers and the subsidiary guarantors and Deutsche Bank Trust Company Americas, as trustee, entered into an indenture (the “Indenture”).

The 6.25% Notes mature on July 15, 2022 with interest accruing at a rate of 6.25% per annum and payable semi-annually in arrears on January 15 and July 15 of each year, commencing January 15, 2015. The 6.25% Notes are guaranteed on a joint and several senior unsecured basis by each of the Issuers and the subsidiary guarantors to the extent set forth in the Indenture. Upon a continuing event of default, the trustee or the holders of at least 25% in principal amount of the 6.25% Notes may declare the 6.25% Notes immediately due and payable, except that an event of default resulting from entry into a bankruptcy, insolvency or reorganization with respect to the Partnership, any restricted subsidiary of the Partnership that is a significant subsidiary or any group of its restricted subsidiaries that, taken together, would constitute a significant subsidiary of the Partnership, will automatically cause the 6.25% Notes to become due and payable.

The Issuers have the option to redeem up to 35% of the 6.25% Notes prior to July 15, 2017 at a redemption price (expressed as a percentage of principal amount) of 106.25% plus accrued and unpaid interest, if any. The Issuers have the option to redeem the 6.25% Notes, in whole or in part, at any time on or after July 15, 2017, at the redemption prices of 104.688% for the twelve-month period beginning on July 15, 2017, 103.125% for the twelve-month period beginning July 15, 2018, 101.563% for the twelve-month period beginning July 15, 2019, and 100.0% beginning on July 15, 2020 and at any time thereafter, together with any accrued and unpaid interest to the date of redemption. In addition, before July 15, 2017, the Issuers may redeem all or any part of the 6.25% Notes at a redemption price equal to the sum of the principal amount thereof, plus a make whole premium at the redemption date, plus accrued and unpaid interest, if any, to the redemption date. The holders of the notes may require the Issuers to repurchase the 6.25% Notes following certain asset sales or a Change of Control (as defined in the Indenture) at the prices and on the terms specified in the Indenture.

The Indenture contains covenants that will limit the Partnership’s ability to, among other things, incur additional indebtedness and issue preferred securities, make certain dividends and distributions, make certain investments and other restricted payments, restrict distributions by its subsidiaries, create liens, enter into sale-leaseback transactions, sell assets or merge with other entities. Events of default under the Indenture include (i) a default in payment of principal of, or interest or premium, if any, on, the 6.25% Notes, (ii) breach of the Partnership’s covenants under the Indenture, (iii) certain events of bankruptcy and insolvency, (iv) any payment default or acceleration of indebtedness of the Partnership or certain subsidiaries if the total amount of such indebtedness unpaid or accelerated exceeds $15.0 million and (v) failure to pay within 60 days uninsured final judgments exceeding $15.0 million.

Registration Rights Agreement

On June 24, 2014, the Issuers and the subsidiary guarantors entered into a registration rights agreement (the “Registration Rights Agreement”) with the Initial Purchasers in connection with the Issuers’ private placement of the 6.25% Notes. Under the Registration Rights Agreement, the Issuers and the subsidiary guarantors agreed to file and use commercially reasonable efforts to cause to become effective a registration statement relating to an offer to exchange the 6.25% Notes for an issue of SEC-registered notes with terms identical to the 6.25% Notes (except that the exchange notes are not subject to restrictions on transfer or to any increase in annual interest rate for failure to comply with the Registration Rights Agreement) that are registered under the Securities Act so as to permit the exchange offer to be consummated by the 360th day after June 24, 2014. The exchange offer was completed on April 21, 2015, and 100% of the 6.25% Notes were exchanged for SEC-registered notes.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

7.00% Senior Notes

On June 1, 2015, the Issuers entered into a Purchase Agreement (the “7.00% Notes Purchase Agreement”) with the Initial Purchasers (as defined therein) (the “7.00% Notes Initial Purchasers”) pursuant to which the Issuers agreed to sell $300.0 million aggregate principal amount of the Issuers’ 7.00% senior notes due 2023 (the “7.00% Notes”) to the 7.00% Notes Initial Purchasers in a private placement exempt from the registration requirements under the Securities Act. The 7.00% Notes were resold by the 7.00% Notes Initial Purchasers to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to persons outside the United States pursuant to RegulationS under the Securities Act.

The 7.00% Notes Purchase Agreement contained customary representations and warranties of the parties and indemnification and contribution provisions under which the Issuers and the subsidiary guarantors, on one hand, and the 7.00% Notes Initial Purchasers, on the other, agreed to indemnify each other against certain liabilities, including liabilities under the Securities Act. In addition, the 7.00% Notes Purchase Agreement required the execution of a registration rights agreement, described below, relating to the 7.00% Notes. Closing of the offering occurred on June 4, 2015.

Indenture

In connection with the private placement of the 7.00% Notes on June 4, 2015 the Issuers and the subsidiary guarantors and Deutsche Bank Trust Company Americas, as trustee, entered into an indenture (the “7.00% Notes Indenture”).

The 7.00% Notes will mature on June 15, 2023 with interest accruing at a rate of 7.00% per annum and payable semi-annually in arrears on June 15 and December 15 of each year, commencing December 15, 2015. The 7.00% Notes are guaranteed on a joint and several senior unsecured basis by each of the Issuers and the subsidiary guarantors to the extent set forth in the 7.00% Notes Indenture. Upon a continuing event of default, the trustee or the holders of at least 25% in principal amount of the 7.00% Notes may declare the 7.00% Notes immediately due and payable, except that an event of default resulting from entry into a bankruptcy, insolvency or reorganization with respect to the Partnership, any restricted subsidiary of the Partnership that is a significant subsidiary or any group of its restricted subsidiaries that, taken together, would constitute a significant subsidiary of the Partnership, will automatically cause the 7.00% Notes to become due and payable.

The Issuers will have the option to redeem up to 35% of the 7.00% Notes prior to June 15, 2018 at a redemption price (expressed as a percentage of principal amount) of 107.00% plus accrued and unpaid interest, if any. The Issuers have the option to redeem the 7.00% Notes, in whole or in part, at any time on or after June 15, 2018, at the redemption prices of 105.250% for the twelve-month period beginning June 15, 2018, 103.500% for the twelve-month period beginning June 15, 2019, 101.750% for the twelve-month period beginning June 15, 2020, and 100.0% beginning June 15, 2021 and at any time thereafter, together with any accrued and unpaid interest to the date of redemption. In addition, before June 15, 2018, the Issuers may redeem all or any part of the 7.00% Notes at a redemption price equal to the sum of the principal amount thereof, plus a make whole premium, plus accrued and unpaid interest, if any, to the redemption date. The holders of the 7.00% Notes may require the Issuers to repurchase the 7.00% Notes following certain asset sales or a Change of Control (as defined in the 7.00% Notes Indenture) at the prices and on the terms specified in the 7.00% Notes Indenture.

The 7.00% Notes Indenture contains covenants that will limit the Partnership’s ability to, among other things, incur additional indebtedness and issue preferred securities, make certain dividends and distributions, make certain investments and other restricted payments, restrict distributions by its subsidiaries, create liens, enter into sale-leaseback transactions, sell assets or merge with other entities. Events of default under the 7.00% Notes Indenture include (i) a default in payment of principal of, or interest or premium, if any, on, the 7.00% Notes, (ii) breach of the Partnership’s

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

covenants under the 7.00% Notes Indenture, (iii) certain events of bankruptcy and insolvency, (iv) any payment default or acceleration of indebtedness of the Partnership or certain subsidiaries if the total amount of such indebtedness unpaid or accelerated exceeds $50.0million and (v) failure to pay within 60 days uninsured final judgments exceeding $50.0million.

Registration Rights Agreement

On June 4, 2015, the Issuers and the subsidiary guarantors entered into a registration rights agreement (the “7.00% Notes Registration Rights Agreement”) with the 7.00% Notes Initial Purchasers in connection with the Issuers’ private placement of the 7.00% Notes. Under the 7.00% Notes Registration Rights Agreement, the Issuers and the subsidiary guarantors agreed to file and use commercially reasonable efforts to cause to become effective a registration statement relating to an offer to exchange the 7.00% Notes for an issue of SEC-registered notes with terms identical to the 7.00% Notes (except that the exchange notes are not subject to restrictions on transfer or to any increase in annual interest rate for failure to comply with the 7.00% Notes Registration Rights Agreement) that are registered under the Securities Act so as to permit the exchange offer to be consummated by the 420th day after June 4, 2015. The exchange offer was completed on October 22, 2015, and 100% of the 7.00% Notes were exchanged for SEC-registered notes.

Line of Credit.

On December 9, 2013, Basin Transload entered into a line of credit facility which allows for borrowings by Basin Transload of up to $10.0 million on a revolving basis. The facility had an outstanding balance of $0 and $0.7 million at December 31, 2015 and 2014, respectively. The facility, which expired on February 9, 2016, was secured by substantially all of the assets of Basin Transload and was not guaranteed by the Partnership or any of its wholly owned subsidiaries.

Financing Obligation

In connection with the Capitol acquisition on June1, 2015, (see Note3) the Partnership assumed a financing obligation of $89.6million associated with two sale-leaseback transactions by Capitol for 53 leased sites that did not meet the criteria for sale accounting. During the term of these leases, which expire in May 2028 and September 2029, in lieu of recognizing lease expense for the lease rental payments, the Partnership incurs interest expense associated with the financing obligation. Interest expense of approximately $5.6million was recorded for the year ended December 31, 2015 and included in interest expense in the accompanying statement of operations. The financing obligation will amortize through expiration of the lease based upon the lease rental payments which were $5.4 million for the year ended December 31, 2015. The financing obligation balance outstanding at December 31, 2015 was $89.8 million.

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 other financing arrangements. The Partnership capitalized deferred financing fees of $19.0million and $24.0 million at December 31, 2015 and 2014, respectively.

Unamortized fees related to the Credit Agreement are included in other current assets and other long-term assets and amounted to $11.2million and $16.0million at December 31, 2015 and 2014, respectively. Unamortized fees related to the senior notes are presented as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts and amounted to $7.8million and $8.0million at December31, 2015 and 2014, respectively.As of December31, 2015, the Partnership adopted ASU 2015-03, “Interest-Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs,” See Note 2.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Amortization expense of approximately $5.9million, $5.6 million and $6.9 million for the years ended December 31, 2015, 2014 and 2013, respectively, are included in interest expense in the accompanying consolidated statements of operations.

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.

In connection with the June 2015 acquisition of retail gasoline stations from Capitol (see Note 3), the Partnership assumed certain environmental liabilities, including future remediation activities required by applicable federal, state or local law or regulation at certain of the retail gasoline stations owned by Capitol. Certain environmental remediation obligations at most of the acquired retail gasoline station assets from Capitol are being funded by third parties who assumed certain liabilities in connection with Capitol’s acquisition of these assets from ExxonMobil Corporation (“ExxonMobil”) in 2009 and 2010 and, therefore, cost estimates for such obligations at these stations are not included in this estimate. As a result, the Partnership initially recorded, on an undiscounted basis, a total environmental liability of approximately $0.3 million for those locations not covered by third parties.

In connection with the January 2015 acquisition of the Revere Terminal (see Note 3), the Partnership assumed certain environmental liabilities, including certain ongoing environmental remediation efforts. As a result, the Partnership initially recorded, on an undiscounted basis, a total environmental liability of approximately $3.1 million.

In connection with the January 2015 acquisition of Warren (see Note 3), the Partnership assumed certain environmental liabilities, including certain ongoing environmental remediation efforts at certain of the retail gasoline stations owned by Warren and future remediation activities required by applicable federal, state or local law or regulation. As a result, the Partnership initially recorded, on an undiscounted basis, a total environmental liability of approximately $36.5 million.

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

In connection with the March 2012 acquisition of Alliance, the Partnership assumed Alliance’s environmental liabilities, including ongoing environmental remediation at certain of the retail gasoline 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 initially 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 initially 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 initially recorded, on an undiscounted basis, a total environmental liability of approximately $1.5 million.

In addition to the above-mentioned environmental liabilities related to the Partnership’s retail gasoline stations, the Partnership retains environmental obligations associated with certain gasoline stations that the Partnership has sold.

The following table presents a summary roll forward of the Partnership’s environmental liabilities at December 31, 2015 (in thousands):

	Balance at								Other		Balance at
	December 31,		Additions		Payments in		Dispositions		Adjustments		December 31,
Environmental Liability Related to:	2014		2015		2015		2015		2015		2015
Retail gasoline stations	$	35,792	$	36,767	$	(3,535)	$	(75)	$	(498)	$	68,451
Terminals		1,771		3,074		(63)		—		—		4,782
Total environmental liabilities	$	37,563	$	39,841	$	(3,598)	$	(75)	$	(498)	$	73,233
Current portion	$	3,101									$	5,350
Long-term portion		34,462										67,883
Total environmental liabilities	$	37,563									$	73,233

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 obligations through divestures of sites and the possibility of existing legal claims giving rise to additional claims. Dispositions generally represent relief of legal obligations through the sale of the related property with no retained obligation. Other adjustments generally represent changes in estimates for existing obligations or obligations associated with new sites. Therefore, although the Partnership believes that these

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 renewable fuel for the purpose of tracking its production, use, and trading as required by the U.S. Environmental Protection Agency’s (“EPA”) Renewable Fuel Standard that originated with the Energy Policy Act of 2005 and modified by the Energy Independence and Security Act of 2007. To evidence that the required volume of renewable fuel is blended with gasoline and diesel motor vehicle fuels, obligated parties must retire sufficient RINs to cover their Renewable Volume Obligation (“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 and a small amount of blending operations at certain facilities. 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 the RVO is a calendar year and the settlement of the RVO typically occurs by March 31 of the following year, the settlement of the RVO can occur, under certain EPA deferral actions, more than one year after the close of the compliance period.

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 that the Partnership does not have a sufficient number of RINs to satisfy the RVO 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. The Partnership’s RVO deficiency was $0.4million and $0.3 million at December 31, 2015 and 2014, respectively.

The Partnership may enter into RIN forward purchase and sales commitments. Total losses at December 31, 2015 and 2014 from firm non-cancellable commitmentswere immaterial.

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):

	2015		2014
Barging transportation, product storage and other ancillary cost accruals	$	13,385	$	19,843
Employee compensation		16,098		26,827
Accrued interest		12,524		12,839
Customer Advance		—		12,000
RIN and RVO deficiency		367		253
Other		17,954		11,058
Total	$	60,328	$	82,820

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 $95.3 million at December31, 2015, which consisted of $55.4 million related to an ethanol credit and $39.9 million in various pass‑through taxes collected on behalf of taxing authorities. Trustee taxes payable at December31, 2014 of $105.7 million consisted of $55.4 million related to an ethanol credit and $50.3 million in various pass‑through taxes collected on behalf of taxing authorities.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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.

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 GMG 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 $2.4 million, $2.0 million and $1.8 million for the years ended December 31, 2015, 2014 and 2013, respectively, which are included in selling, general and administrative expenses in the accompanying statements of operations.

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.

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

	December 31,  2015
	Global		GMG
	Pension Plan		Pension Plan		Total
Projected benefit obligation	$	16,338	$	4,593	$	20,931
Fair value of plan assets		13,481		3,405		16,886
Net unfunded pension liability	$	2,857	$	1,188	$	4,045

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	December 31,  2014
	Global		GMG
	Pension Plan		Pension Plan		Total
Projected benefit obligation	$	18,333	$	5,282	$	23,615
Fair value of plan assets		14,545		3,478		18,023
Net unfunded pension liability	$	3,788	$	1,804	$	5,592

Total actual return on plan assets was ($0.2 million) and $1.2 million in 2015 and 2014, respectively.

The following presents the components of the net periodic change in benefit obligation for the Pension Plans for the years ended December 31 (in thousands):

	2015		2014		2013
Benefit obligation at beginning of year	$	23,615	$	19,245	$	23,073
Interest cost		801		804		730
Actuarial (gain) loss		(1,925)		5,151		(2,419)
Benefits paid		(1,559)		(1,585)		(2,139)
Benefit obligation at end of year	$	20,932	$	23,615	$	19,245

The following presents the weighted-average actuarial assumptions used in determining each plan’s annual pension expense for the years ended December 31:

	Global Pension Plan			GMG Pension Plan
	2015	2014	2013	2015	2014	2013
Discount rate	4.0%	3.6%	4.4%	4.3%	3.6%	4.4%
Expected return on plan assets	7.0%	7.5%	7.5%	7.0%	7.0%	7.0%

The discount rates were selected by performing a cash flow/bond matching analysis based on the Citigroup Above‑Median Pension Discount Curve. 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 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.

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following presents the Pension Plans’ benefits as of December 31, 2015 expected to be paid in each of the next five fiscal years and in the aggregate for the next five fiscal years thereafter (in thousands):

2016	$	2,001
2017		2,436
2018		833
2019		808
2020		1,334
2021—2025		4,933
Total	$	12,345

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 $0.6million, $0.2million and $0.5 million in 2015, 2014 and 2013, respectively.

Note 12. Long-Term Incentive Plan

The Partnership has a Long Term Incentive Plan, as amended (the “LTIP”), whereby a total of 4,300,000 common units were authorized for delivery with respect to awards under the LTIP. The 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 LTIP allows for the award of options, unit appreciation rights, restricted units, phantom units, distribution equivalent rights, unit awards and substitute awards.

Awards granted under the LTIP are authorized by the Compensation Committee of the board of directors of the General Partner (the “Committee”) from time to time. Additionally and in accordance with the LTIP, the Committee established a “CEO Authorized LTIP” program pursuant to which the Chief Executive Officer (“CEO”) may grant awards of phantom units without distribution equivalent rights to employees of the General Partner and the Partnership’s subsidiaries, other than named executive officers. The CEO Authorized LTIP program was approved for three consecutive calendar years commencing January 1, 2014, subject to modification or earlier termination by the Committee. During each calendar year of the program, the CEO is authorized to grant awards of up to an aggregate amount of $2.0 million of phantom units payable in common units upon vesting, with unused dollar amounts carrying over in the next year, and no individual grant may be made for an award valued at the time of grant of more than $550,000, unless otherwise previously approved by the Committee. Awards granted pursuant to the CEO Authorized LTIP generally would be for a term of six years and vest in equal tranches at the end of each of the fourth, fifth and sixth anniversary dates of the particular award.

Phantom Unit Awards

In 2013, the Committee granted a total of 498,112 phantom units under the 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. On December 31, 2014, a total of 10,266 of the awards granted to one employee and the non-employee directors vested and in January 2015, these phantom unit grants were settled.

In 2014, a total of 44,902 phantom units were granted to certain employees.

In 2015, a total of 76,893 phantom units were granted to certain employees and the non-employee directors.

The phantom units for these awards vest pursuant to the terms of the grant agreements. The Partnership

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

currently intends and reasonably expects to issue and deliver the common units upon vesting.

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 above awards at their respective grant dates 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 awards, is recognized over the requisite service period. The requisite service period for the Partnership is from the grant date through the vesting dates described in the grant agreement. The Partnership recognizes 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 total compensation expense related to the above awards of $4.3 million, $3.5 million and $1.7 million for the years ended December 31, 2015, 2014 and 2013, respectively, which is included in selling, general and administrative expenses in the accompanying consolidated statements of operations. The total compensation cost related to the non-vested awards not yet recognized at December 31, 2015 was approximately $14.4 million and is expected to be recognized ratably over the remaining requisite service periods.

Status of Non‑Vested Units

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

		Weighted
	Number of	Average
	Non-vested	Grant Date
	Units	Fair Value
Outstanding non—vested units at December 31, 2013	498,112	$	39.29
Granted	44,902		39.34
Vested	(10,266)		39.29
Forfeited	—		—
Outstanding non—vested units at December 31, 2014	532,748		39.29
Granted	76,893		35.72
Vested	(13,921)		38.39
Forfeited	—		—
Outstanding non—vested units at December 31, 2015	595,720	$	38.85

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 authorized to acquire up to 1,242,427 of its common units in the aggregate over an extended period of time, consistent with the General Partner’s Obligations. 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 and economic and market conditions, applicable legal requirements and available liquidity. Since the Repurchase Program was implemented, the

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

General Partner has repurchased 838,505 common units pursuant to the Repurchase Program for approximately $24.8 million, of which approximately $3.9 million was purchased during 2015.

Common units outstanding as reported in the accompanying consolidated financial statements at December 31, 2015 and 2014 excluded 403,922 and 390,602 common units, respectively, held on behalf of the Partnership pursuant to its Repurchase Program and for future satisfaction of the General Partner’s Obligations.

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, 2015 (in thousands):

2016	$	2,816
2017		2,743
2018		2,644
2019		2,650
2020		2,297
Thereafter		13,840
Total	$	26,990

Total rent expense under the operating lease arrangements amounted to approximately $2.5 million, $2.7 million and $2.7 million for the years ended December 31, 2015, 2014 and 2013, 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.

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 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, 2015 (in thousands):

2016	$	14,984
2017		8,353
2018		723
2019		132
Total	$	24,192

Total rent expense reflected in cost of sales related to these operating leases were approximately $22.5 million, $31.5 million and $35.5 million for the years ended December 31, 2015, 2014 and 2013, respectively.

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Leases of Gasoline Stations

The Partnership 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, 2015 (in thousands):

2016	$	29,432
2017		26,102
2018		23,365
2019		20,712
2020		18,236
Thereafter		98,193
Total	$	216,040

Total expenses under these operating lease arrangements amounted to approximately $29.4 million, $19.7 million and $17.7 million for the years ended December 31, 2015, 2014 and 2013, respectively. The increase in total expenses in 2015 compared to 2014 and 2013 was primarily due to the January 2015 acquisition of Warren and the June 2015 acquisition of Capitol.

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, 2015 was $368.4 million, net of accumulated depreciation of approximately $48.7 million. The following provides future minimum rental income under non‑cancellable operating leases associated with these properties at December 31, 2015 (in thousands):

2016	$	45,125
2017		23,781
2018		7,797
2019		1,212
2020		1,079
Thereafter		17,001
Total	$	95,995

Total rental income, which includes reimbursement of utilities and property taxes in certain cases, amounted to approximately $61.1million, $42.5 million and $41.3 million for the years ended December 31, 2015, 2014 and 2013, respectively. The increase in rental income in 2015 compared to 2014 and 2013 was primarily due to the January 2015 acquisition of Warren and the June 2015 acquisition of Capitol.

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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, 2015 (in thousands):

2016	$	59,625
2017		52,186
2018		45,968
2019		28,532
2020		2,257
Thereafter		608
Total	$	189,176

The minimum lease commitments for 2016 and 2017 are net of $10.8 million and $2.7 million, respectively, related to a contractual sub-lease arrangement that expires in 2017.

Total expenses under these operating lease arrangements amounted to approximately $57.7million, $56.9 million and $28.9 million for the years ended December 31, 2015, 2014 and 2013, respectively.

Leases of Barges

The Partnership leases barges through various time charter 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, 2015 (in thousands):

2016	$	58,256
2017		45,854
2018		36,440
2019		12,223
2020		1,983
Total	$	154,756

Total expenses under these operating lease arrangements amounted to approximately $87.3million, $60.6 million and $37.1 million for the years ended December 31, 2015, 2014 and 2013, respectively. The increase in expenses was due to the Partnership leasing more barges under time charters compared to previous periods.

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Purchase 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, 2015, the Partnership has fulfilled all gallonage commitments. The following provides minimum volume purchase requirements at December 31, 2015 (in thousands of gallons):

2016	397,600
2017	331,900
2018	330,100
2019	327,700
2020	312,700
Thereafter	828,300
Total	2,528,300

Brand Fee Agreement

The Partnership entered into a brand fee agreement with ExxonMobil which entitles the Partnership to operate 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 gasoline stations acquired from ExxonMobil in 2010, 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, 2015 (in thousands):

2016	$	9,000
2017		9,000
2018		9,000
2019		9,000
2020		9,000
Thereafter		40,500
Total	$	85,500

Total expenses reflected in cost of sales related this agreement were approximately $9.0 million for each of the years ended December 31, 2015, 2014 and 2013.

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Port of St. Helens Agreements—Land and Equipment

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, 2015 (in thousands):

2016	$	223
2017		223
2018		223
2019		223
2020		223
Thereafter		10,128
Total	$	11,243

Total rental expense was approximately $223,000, $222,000 and $180,000 for the years ended December 31, 2015, 2014 and 2013, respectively.

Other Commitments

In June 2014, the Partnership entered into a pipeline connection agreement with Meadowlark Midstream Company, LLC (“Meadowlark”) whereby Meadowlark would construct, own, operate and maintain a crude oil pipeline from its Divide County, North Dakota crude oil station to the Partnership’s Basin Transload crude oil storage facility in Columbus, North Dakota. In connection with the agreement, the Partnership is committed to a minimum take-or-pay throughput commitment of approximately $55.0 million over a seven–year period beginning after the commissioning of the pipeline which occurred in December of 2015. At December 31, 2015, the remaining commitment on the take-or-pay commitment was approximately $55.0 million.

In May 2014, the Partnership entered into a pipeline connection agreement with Tesoro High Plains Pipeline Company (“Tesoro High Plains”) whereby Tesoro High Plains would design, engineer, construct and place in service improvements on its pipeline system that will expand its capacity to ship crude oil from points in Dunn and McKenzie Counties, North Dakota to Ramberg Station/Beaver Lodge destination point in Williams County, North Dakota. In connection with this agreement, the Partnership is committed to a minimum take-or-pay throughput commitment of approximately $36.4 million over a seven–year period beginning after the commissioning of the pipeline, which occurred in January of 2015. At December 31, 2015, the remaining commitment on the take-or-pay commitment, including a quarterly take-or-pay of $1.3 million, was approximately $31.2 million.

In April 2014, the Partnership entered into a pipeline connection agreement with Tesoro whereby Tesoro would build, own and operate a four‑mile pipeline lateral from its existing block gate valve in Mercer Country, North Dakota to the Partnership’s Beulah Rail Facility near Beulah, North Dakota. In connection with this agreement, the Partnership is committed to a minimum take-or-pay throughput commitment of approximately $8.7 million over a five‑year period beginning after the commissioning of the pipeline, which occurred in November 2014. At December31, 2015, the remaining commitment on the take-or-pay commitment was approximately $8.1 million.

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 five–year period beginning after the commissioning of the pipeline, which occurred in August of 2013. At December 31, 2015, the remaining commitment on the take‑or‑pay commitment was $0.

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

In February 2013, the Partnership assumed natural gas transportation and reservation agreements,which have various expiration dates, with Northwest Natural Gas Company (“NWNatural Gas”) and the Northwest Pipeline system (“NWPipeline”) whereby NWNatural and NWPipeline provide the Partnership with the transportation and reservation of firm natural gas delivered to the Partnership’s Oregon facility. At December31, 2015,  the remaining commitment on the transportation and reservation agreements was approximately $14.3million.

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

Partners’ Equity

Partners’ equity at December 31, 2015 consisted of 33,995,563 common units issued, including 7,434,775 common units held by affiliates of the General Partner, including directors and executive officers, collectively representing a 99.33% limited partner interest in the Partnership, and 230,303 general partner units representing a 0.67% general partner interest in the Partnership.

The following table presents the changes in the Partnership’s outstanding units:

	Limited Partner Units	General Partner Equivalent Units	Total
Balance at December 31, 2013	27,430,563	230,303	27,660,866
Public offering of common units (see Note 15)	3,565,000	—	3,565,000
Balance at December 31, 2014	30,995,563	230,303	31,225,866
Public offering of common units (see Note 15)	3,000,000	—	3,000,000
Balance at December 31, 2015	33,995,563	230,303	34,225,866

Partners’ equity at December 31, 2015 and 2014 excluded common units outstanding of 403,922 and 390,602, respectively, held pursuant to the Repurchase Program and for future satisfaction of the General Partner’s Obligations (defined herein). See Note 12, “Long‑Term Incentive Plan—Repurchase Program.”

Common Units

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

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.

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 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.

Cash Distributions

The Partnership intends 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. 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.The indentures governing the Partnership’s outstanding senior notes also limit the Partnership’s ability to make distributions to its unitholders in certain circumstances.

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: 99.33% to the common unitholders, pro rata, and 0.67% 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.

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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
	Total Quarterly Distribution	Interest in Distributions
	Target Amount	Unitholders		General Partner
First Target Distribution	upto $0.4625	99.33	%	0.67	%
Second Target Distribution	above $0.4625 up to $0.5375	86.33	%	13.67	%
Third Target Distribution	above $0.5375 up to $0.6625	76.33	%	23.67	%
Thereafter	above $0.6625	51.33	%	48.67	%

The Partnership paid the following cash distributions during 2015, 2014 and 2013 (in thousands, except per unit data):

	Earned for the	Per Unit
Cash Distribution	Quarter	Cash		Common		General		Incentive		Total Cash
Payment Date	Ended	Distribution		Units		Partner		Distribution		Distribution
2013
02/14/13 (1)(2)	12/31/12	$	0.5700	$	15,636	$	131	$	579	$	16,346
05/15/13 (1)(2)	03/31/13		0.5825		15,979		134		683		16,796
08/14/13 (1)(2)	06/30/13		0.5875		16,116		135		724		16,975
11/14/13 (1)(2)	09/30/13		0.6000		16,459		138		828		17,425
2014
02/14/14 (1)(2)	12/31/13	$	0.6125	$	16,802	$	140	$	932	$	17,874
05/15/14 (1)(2)	03/31/14		0.6250		17,145		143		1,035		18,323
08/14/14 (1)(2)	06/30/14		0.6375		17,487		146		1,139		18,772
11/14/14 (1)(2)	09/30/14		0.6525		17,899		150		1,270		19,319
2015
02/13/15 (3)(4)	12/31/14	$	0.6650	$	20,612	$	154	$	1,591	$	22,357
05/15/15 (3)(4)	03/31/15		0.6800		21,076		157		2,027		23,260
08/14/15 (4)	06/30/15		0.6925		23,543		159		2,618		26,320
11/13/15 (4)	09/30/15		0.6975		23,713		160		2,777		26,650

(1) Prior to the Partnership’s public offering in December 2014 (see Note 15), the limited partner interest was 99.17% and the general partner interest was 0.83%.

(2) This distribution resulted in the Partnership exceeding its second target level distribution for the respective quarter. As a result, the General Partner, as the holder of the IDRs, received an incentive distribution.

(3) Prior to the Partnership’s public offering in June 2015 (see Note 15), the limited partner interest was 99.26% and the general partner interest was 0.74%.

(4) This distribution resulted in the Partnership exceeding its third target level distribution for the respective quarter. As a result, the General Partner, as the holder of the IDRs, received an incentive distribution.

In addition, on January 28, 2016, the board of directors of the General Partner declared a quarterly cash distribution of $0.4625 per unit ($1.85 per unit on an annualized basis) on all of its outstanding common units for the period from October 1, 2015 through December 31, 2015 to the Partnership’s unitholders of record as of the close of business February 10, 2016. On February 16, 2016, the Partnership paid the total cash distribution of approximately $15.8 million.

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 15. Unitholders’ Equity

Equity Offerings

On June 11, 2015, the Partnership entered into an Underwriting Agreement (the “2015 Underwriting Agreement”) relating to the public offering of 3,000,000 common units at a price to the public of $38.12 per common unit. On June 16, 2015, the Partnership completed the offering, and the net proceeds of approximately $109.3 million (after deducting underwriting discounts and estimated expenses) were used to reduce indebtedness outstanding under the Partnership’s revolving credit facility.

On December 5, 2014, the Partnership entered into an Underwriting Agreement (the “2014 Underwriting Agreement”) relating to the public offering of 3,565,000 common units at a price to the public of $40.24 per common unit. On December 10, 2014, the Partnership completed the offering, and the net proceeds of approximately $137.8 million (after deducting underwriting discounts and estimated expenses) were used to reduce indebtedness outstanding under the Partnership’s revolving credit facility.

At-the-Market Offering Program

On May 19, 2015, the Partnership entered into an equity distribution agreement pursuant to which the Partnership may sell from time to time through its sales agents, the Partnership’s common units having an aggregate offering price of up to $50.0 million. Sales of the common units, if any, will be made by any method permitted by law deemed to be an “at-the-market” offering, including ordinary brokers’ transactions through the facilities of the New York Stock Exchange, to or through a market maker, or directly on or through an electronic communication network, a “dark pool” or any similar market venue, at market prices, in block transactions, or as otherwise agreed upon by the Partnership and one or more of its sales agents.

The Partnership may also sell common units to one or more of its sales agents as principal for its own account at a price to be agreed upon at the time of sale. Any sale of common units to a sales agent as principal would be pursuant to the terms of a separate agreement between the Partnership and such sales agent.

The Partnership intends to use the net proceeds from any sales pursuant to the at-the-market offering program, after deducting the sales agents’ commissions and the Partnership’s offering expenses, for general partnership purposes, which may include, among other things, repayment of indebtedness, acquisitions and capital expenditures.

The sales agents and/or affiliates of each of the sales agents have, from time to time, performed, and may in the future perform, various financial advisory and commercial and investment banking services for the Partnership and its affiliates, for which they have received and in the future will receive customary compensation and expense reimbursement. Affiliates of the sales agents are lenders under the Partnership’s credit facility and, accordingly, may receive a portion of the net proceeds from this offering if and to the extent any proceeds are used to reduce outstanding borrowings under the Partnership’s credit facility.

As of December 31, 2015, no common units were sold by the Partnership pursuant to the at-the-market offering program.

Note 16. Related‑Party Transactions

The Partnership was a party to an exclusive Second Amended and Restated Terminal Storage Rental and Throughput Agreement, as amended (the “Terminal Storage Rental and Throughput Agreement”), with GPC, an affiliate of the Partnership that is 100% owned by members of the Slifka family, with respect to the Revere Terminal in Revere, Massachusetts. On January 14, 2015, the Partnership acquired the Revere Terminal from GPC and related entities, and

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

the Terminal Storage Rental and Throughput Agreement was terminated (see Note 3). Prior to the acquisition, the agreement was accounted for as an operating lease. The expenses under this agreement totaled $0.8 million, $9.2 million and $9.1 million for the years ended December31, 2015, 2014 and 2013, respectively. These expenses include annual consumer price index adjustments of approximately $0, $1.9million and $1.8 million for the years ended December31, 2015, 2014 and 2013, respectively.

The Partnership was a party to an Amended and Restated Services Agreement with GPC, whereby GPC provided certain terminal operating management services to the Partnership and used certain administrative, accounting and information processing services of the Partnership. The expenses from these services totaled approximately $8,000, $96,000 and $96,000 for the years ended December 31, 2015, 2014 and 2013, respectively.  These charges were recorded in selling, general and administrative expenses in the accompanying consolidated statements of operations.

On March 11, 2015, the Partnership entered into the following amendments and restatements to its shared services agreements: (i) Global Companies entered into an Amended and Restated Services Agreement with AE Holdings Corp. (the “AE Holdings Amended and Restated Services Agreement”), and (ii) certain of the Partnership’s subsidiaries entered into a Second Amended and Restated Services Agreement with GPC (the “GPC Second Amended and Restated Services Agreement”).

Under the AE Holdings Amended and Restated Services Agreement, the Partnership provided AE Holdings with certain tax, accounting, treasury and legal support services for which AE Holdings paid the Partnership an aggregate of $15,000 per year in equal monthly installments until it was voluntarily dissolved effective on July 10, 2015. Under the GPC Second Amended and Restated Services Agreement, GPC no longer provides the Partnership with terminal, environmental and operational support services, but the Partnership continues to provide GPC with certain tax, accounting, treasury, legal, information technology, human resources and financial operations support services for which GPC pays the Partnership a monthly services fee at an agreed amount subject to the approval by the Conflicts Committee of the board of directors of the General Partner. The GPC Second Amended and Restated Services Agreement  is for an indefinite term and any party may terminate some or all of the services upon ninety (90) days’ advanced written notice. As of December 31, 2015, no such notice of termination was given by GPC.

The General Partner employs substantially all of the Partnership’s employees, except for most of 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 $109.0 million, $95.5 million and $79.3 million for the years ended December 31, 2015, 2014 and 2013, respectively. The Partnership 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):

	2015		2014
Receivables from GPC	$	—	$	108
Receivables from the General Partner (1)		2,578		3,795
Total	$	2,578	$	3,903

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

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 17. Segment Reporting

The Partnership engages in the purchasing, selling, storing and logistics of transporting petroleum and related products, including domestic and Canadian crude oil, gasoline and gasoline blendstocks (such as ethanol), distillates (such as home heating oil, diesel and kerosene), residual oil, renewable fuels, natural gas and propane. The Partnership also receives revenue from convenience store sales and gasoline station rental income. 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, GDSO 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 December31, 2015, 2014 and 2013, 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 branded and unbranded gasoline and gasoline blendstocks and diesel to wholesale distributors.The Partnership transports these products by railcars, barges and/or pipelines pursuant to spot or long‑term contracts.  The Partnership aggregates crude oil by truck or pipeline in the mid-continent region of the United States and Canada, transports it by train and ships it by barge to refiners on the East and West Coasts. The Partnership sells home heating oil, diesel, kerosene, residual oil and propane to home heating oil and propane retailers and wholesale distributors. Generally, customers use their own vehicles or contract carriers to take delivery of the gasoline and distillates at bulk terminals and inland storage facilities that the Partnership owns or controls or with which it has throughput or exchange arrangements. Additionally, ethanol is shipped primarily by rail and by barge.

In the GDSO reporting segment, gasoline distribution includes sales of branded and unbranded gasoline to gasoline station operators and sub jobbers. Station operations include (i) convenience stores, (ii) rental income from gasoline stations leased to dealers, from commissioned agents and from cobranding arrangements and (iii) sundries (such as car wash sales, lottery and ATM commissions). The results of Warren, acquired in January 2015, and Capitol, acquired in June 2015 (see Note 3), are included in the GDSO segment.

In the Commercial segment, the Partnership 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, bunker fuel and natural gas. In the case of public sector commercial and industrial end user customers, the Partnership sells products primarily either through a competitive bidding process or through contracts of various terms. The Partnership generally arranges for the delivery of the product to the customer’s designated location, and the Partnership responds to publicly-issued requests for product proposals and quotes. The Commercial segment also includes sales of custom blended fuels delivered by barges or from a terminal dock to ships through bunkering activity.

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.

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (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,
	2015		2014		2013
Wholesale Segment:
Sales
Gasoline and gasoline blendstocks	$	2,714,057	$	7,076,105	$	8,085,225
Crude oil (1)		1,190,560		2,384,018		3,561,428
Other oils and related products (2)		2,006,668		3,436,006		3,559,001
Total	$	5,911,285	$	12,896,129	$	15,205,654
Product margin
Gasoline and gasoline blendstocks	$	66,031	$	71,713	$	43,147
Crude oil (1)		74,182		141,965		92,807
Other oils and related products (2)		67,709		79,376		66,916
Total	$	207,922	$	293,054	$	202,870
Gasoline Distribution and Station Operations Segment (3):
Sales
Gasoline	$	3,289,742	$	3,241,620	$	3,231,925
Station operations (4)		381,194		165,756		146,503
Total	$	3,670,936	$	3,407,376	$	3,378,428
Product margin
Gasoline	$	276,848	$	189,439	$	150,147
Station operations (4)(5)		178,487		93,939		78,833
Total	$	455,335	$	283,378	$	228,980
Commercial Segment:
Sales	$	732,631	$	966,449	$	1,005,526
Product margin	$	29,201	$	29,716	$	28,359
Combined sales and Product margin:
Sales	$	10,314,852	$	17,269,954	$	19,589,608
Product margin (6)	$	692,458	$	606,148	$	460,209
Depreciation allocated to cost of sales		(94,789)		(61,361)		(55,653)
Combined gross profit	$	597,669	$	544,787	$	404,556

(1) Crude oil consists of the Partnership’s crude oil sales and revenue from its logistics activities.

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

(3) The GDSO segment for 2015 includes the results of the January 2015 acquisition of Warren and the June 2015 acquisition of Capitol (see Note 3). As the Warren assets and the Capitol assets were not in place prior to 2015, the above results are not directly comparable to the prior periods.

(4) Station operations primarily consist of convenience store salesandrental income.

(5) For the years ended December 31, 2014 and 2013, station operations includes the reclass of loss (gain) on sale and disposition of assets from product margin to operating expenses to conform to the Partnership’s current presentation.

(6) Product margin is a non-GAAP financial measure used by management and external users of the Partnership’s consolidated financial statements to assess its business. The table above includes a reconciliation of product margin on a combined basis to gross profit, a directly comparable GAAP measure.

Approximately 450million gallons, 450million gallons and 500million gallons of the GDSO segment’s sales were supplied from petroleum products and renewable fuels sourced by the Wholesale segment for the years ended December31, 2015, 2014 and 2013, respectively. Except for natural gas, predominantly all of the Commercial segment’s sales are sourced by the Wholesale segment. These intra-segment sales are not reflected as sales in the Wholesale segment as they are eliminated.

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

None of the Partnership’s customers accounted for greater than 10% of total sales for year ended December 31, 2015. In the Wholesale segment, the Partnership had one customer, ExxonMobil, whose revenues were approximately $2.9billion (17%) of the Partnership’s total revenues for the year ended December31, 2014 and two significant customers, ExxonMobil and Phillips66, whose revenues were approximately $2.9 billion (15%) and $2.4 billion (12%), respectively, of the Partnership’s total revenues for the year ended December31, 2013.

A reconciliation of the totals reported for the reportable segments to the applicable line items in the consolidated financial statements for the years ended December31 is as follows (in thousands):

	2015		2014		2013
Combined gross profit	$	597,669	$	544,787	$	404,556
Operating costs and expenses not allocated to operating segments:
Selling, general and administrative expenses		177,043		153,961		115,491
Operating expenses		290,307		204,070		185,713
Amortization expense		13,499		18,867		19,216
Loss (gain) on sale and disposition of assets		2,097		2,182		(1,273)
Total operating costs and expenses		482,946		379,080		319,147
Operating income		114,723		165,707		85,409
Interest expense		(73,332)		(47,764)		(43,537)
Income tax benefit (expense)		1,873		(963)		(819)
Net income		43,264		116,980		41,053
Net loss (income) attributable to noncontrolling interest		299		(2,271)		1,562
Net income attributable to Global Partners LP	$	43,563	$	114,709	$	42,615

The Partnership’s foreign assets and foreign sales were immaterial as of and for the years ended December31, 2015 and 2014. In 2013, the Partnership’s foreign assets were immaterial and there were no foreign sales.

Segment Assets

The Partnership acquired retail gasoline stations from Capitol in June 2015 and Warren in January 2015 which were allocated to the GDSO segment. The Partnership acquired the Revere Terminal in January 2015 which was allocated to the Wholesale segment.

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.

The table below presents total assets by reportable segment at December31, (in thousands):

		Wholesale		Commercial		GDSO		Unallocated		Total
December 31, 2015	$	774,352	$	3,224	$	1,392,397	$	493,702	$	2,663,675
December 31, 2014	$	807,708	$	3,827	$	622,860	$	596,422	$	2,030,817

The increase in total assets allocated to GDSO at December 31, 2015 compared to December31, 2014 is due to the January 2015 acquisition of Warren and the June 2015 acquisition of Capitol (see Note 3).

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 18. Fair Value Measurements

Recurring Fair Value Measures

Assets and liabilities are classified in the entirety based on the lowest level of input that is significant to the fair value measurement. The Partnership’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value assets and liabilities and their placement within the fair value hierarchy levels. The following tables present, by level within the fair value hierarchy, the Partnership’s financial assets and liabilities that were measured at fair value on a recurring basis as of December31, 2015 and 2014 (in thousands):

	Fair Value at December 31, 2015
							Cash Collateral
	Level 1		Level 2		Level 3		Netting		Total
Assets:
Forward derivative contracts (1)	$	—	$	62,382	$	3,717	$	—	$	66,099
Foreign currency derivatives		—		10		—		—		10
Interest rate cap		—		—		—		—		—
Exchange-traded/cleared derivative instruments (2)		95,367		—		—		(64,040)		31,327
Pension plan		16,886		—		—		—		16,886
Total assets	$	112,253	$	62,392	$	3,717	$	(64,040)	$	114,322
Liabilities:
Forward derivative contracts (1)	$	—	$	(27,602)	$	(3,653)	$	—	$	(31,255)
Swap agreements and options		—		(656)		—		—		(656)
Interest rate swaps		—		(3,343)		—		—		(3,343)
Total liabilities	$	—	$	(31,601)	$	(3,653)	$	—	$	(35,254)

	Fair Value at December 31, 2014
							Cash Collateral
	Level 1		Level 2		Level 3		Netting		Total
Assets:
Forward derivative contracts (1)	$	—	$	81,421	$	2,405	$	—	$	83,826
Foreign currency derivatives		—		9		—		—		9
Interest rate cap		—		17		—		—		17
Exchange-traded/cleared derivative instruments (2)		121,490		—		—		(104,292)		17,198
Pension plan		18,023		—		—		—		18,023
Total assets	$	139,513	$	81,447	$	2,405	$	(104,292)	$	119,073
Liabilities:
Forward derivative contracts (1)	$	—	$	(28,500)	$	(27,928)	$	—	$	(56,428)
Swap agreements and options		—		(2,079)		—		—		(2,079)
Interest rate swaps		—		(6,696)		—		—		(6,696)
Total liabilities	$	—	$	(37,275)	$	(27,928)	$	—	$	(65,203)

(1) Forward derivative contracts include the Partnership’s petroleum and ethanol physical and financial forwards and OTC swaps

(2) Amount includes the effect of cash balances on deposit with clearing brokers.

F-65

GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 facility approximates fair value due to the variable rate nature of these financial instruments.

The carrying value of the inventory qualifying for fair value hedge accounting approximates fair value due to adjustments for changes in fair value of the hedged item. The fair values of the derivatives used by the Partnership are disclosed in Note4.

The determination of the fair values above incorporates factors including not only the credit standing of the counterparties involved, but also the impact of the Partnership’s nonperformance risks on its liabilities.

The values of the Level1 exchange-traded/cleared derivative instruments and pension plan assets were determined using quoted prices in active markets for identical assets. Specifically, the fair values of the Level1 exchange-traded/cleared derivative instruments were based on quoted process obtained from the NYMEX, CME and ICE. The fair values of the Partnership’s Level1 pension plan assets were based on quoted prices for identical assets which primarily consisted of fixed income securities, equity securities and cash and cash equivalents.

The values of the Level2 derivative contracts were calculated using expected cash flow models and market approaches based on observable market inputs, including published and quoted commodity pricing data, which is verified against other available market data. Specifically, the fair values of the Level2 derivative commodity contracts were derived from published and quoted NYMEX, CME, ICE, New York Harbor and third-party pricing information for the underlying instruments using market approaches. The fair value of the Level2 interest rate instruments were derived from the implied forward LIBOR yield curve for the sale period as the future interest rate swap and interest rate cap settlements using expected cash flow models. The fair value of the Level2 foreign currency derivatives were derived from the implied forward currency curve for the Canadian and U.S. Dollar. The Partnership has not changed its valuation techniques or Level2 inputs during the years ended December31, 2015 and 2014.

The carrying values and fair values of the Partnership’s 6.25% Notes and 7.00% Notes, estimated by observing market trading prices of the 6.25% Notes and 7.00% Notes, respectively, were as follows (in thousands):

	December 31, 2015					December 31, 2014
	Carrying			Fair		Carrying		Fair
	Value			Value		Value		Value
6.25% Notes		$	375,000	$	307,500	$	375,000	$	358,594
7.00% Notes		$	300,000	$	249,000	$	—	$	—

Level 3 Information

The values of the Level3 derivative contracts were calculated using market approaches based on a combination of observable and unobservable market inputs, including published and quoted NYMEX, CME, ICE, New York Harbor and third-party pricing information for a component of the underlying instruments as well as internally developed assumptions where there is little, if any, published or quoted prices or market activity. The unobservable inputs used in the measurement of the Level3 derivative contracts include estimates for location basis, transportation and throughput costs net of an estimated margin for current market participants. The estimates for these inputs for crude oil were  $4.00 to $13.55 per barrel and $11.00 to $18.00 per barrel for the years ended December31, 2015 and 2014, respectively. The estimates for these inputs for propane were $2.10 to $9.66per barrel for the year ended December31, 2015. Gains and losses recognized in earnings (or changes in net assets) are disclosed in Note4.

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Sensitivity of the fair value measurement to changes in the significant unobservable inputs is as follows:

Significant			ImpactonFairValue
Unobservable Input	Position	ChangetoInput	Measurement
Location basis	Long	Increase(decrease)	Gain (loss)
Location basis	Short	Increase(decrease)	Loss (gain)
Transportation	Long	Increase(decrease)	Gain (loss)
Transportation	Short	Increase(decrease)	Loss (gain)
Throughput costs	Long	Increase(decrease)	Gain (loss)
Throughput costs	Short	Increase(decrease)	Loss(gain)

The following table presents a reconciliation of changes in fair value of the Partnership’s derivative contracts classified as Level3 in the fair value hierarchy at December31 (in thousands):

Fair value at December 31, 2014	$	(25,523)
Transfers into Level 3 (1)(2)		516
Realized and unrealized gains (losses) recorded in cost of sales		25,071
Fair value at December 31, 2015	$	64

(1) Transfers from Level 2 to Level 3 were due to certain market inputs associated with propane that were previously considered observable that became unobservable during the year ended December 31, 2015, given increased volatility in the market for this product.

(2) The Partnership’s policy is to recognize transfers between levels with the fair value hierarchy as of the beginning of the reporting period.

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Non-Recurring Fair Value Measures

Certain nonfinancial assets and liabilities are measured at fair value on a non-recurring basis and are subject to fair value adjustments in certain circumstances, such as acquired assets and liabilities or losses related to firm non-cancellable purchase commitments. 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 year ended December 31, 2015.

Note 19. Changes in Accumulated Other Comprehensive Loss

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

	Pension Plan		Derivatives		Total
Balance at December 31, 2013	$	(454)	$	(10,856)	$	(11,310)
Other comprehensive (loss) income before reclassifications of gain (loss)		(4,660)		3,151		(1,509)
Amount of gain (loss) reclassified from accumulated other comprehensive (loss) income		(433)		—		(433)
Total comprehensive (loss) income		(5,093)		3,151		(1,942)
Balance at December 31, 2014		(5,547)		(7,705)		(13,252)
Other comprehensive income before reclassifications of gain (loss)		1,192		4,047		5,239
Amount of gain (loss) reclassified from accumulated other comprehensive (loss) income		(81)		—		(81)
Total comprehensive income		1,111		4,047		5,158
Balance at December 31, 2015	$	(4,436)	$	(3,658)	$	(8,094)

Amounts are presented prior to the income tax effect on other comprehensive income. Given the Partnership’s master limited partnership status, the effective tax rate is immaterial.

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

In February 2016, the Partnership received a request for information from the EPA seeking certain information regarding the Albany Terminal in order to assess its compliance with the Clean Air Act (the “CAA”). The information requested generally relates to crude oil received by, stored at and shipped from the Partnership’s petroleum product

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

transloading facility in Albany, New York (the “Albany Terminal”), including its composition, control devices for emissions and various permitting-related considerations. The Albany Terminal is a 63-acre licensed, permitted and operational stationary bulk petroleum storage and transfer terminal that currently consists of petroleum product storage tanks, along with truck, rail and marine loading facilities, for the storage, blending and distribution of various petroleum and related products, including gasoline, ethanol, distillates, heating and crude oils. The Partnership intends to cooperate fully with the agency and believes the responsive information will demonstrate that the Partnership’s operations at the Albany Terminal are in compliance with all pertinent requirements.

By letter dated October 5, 2015, the Partnership received a notice of intent to sue (the “October NOI”), which supersedes and replaces a prior notice of intent to sue that the Partnership received on September 1, 2015 (the “September NOI”) from Earthjustice, an environmental advocacy organization on behalf of the County of Albany, New York, a public housing development owned and operated by the Albany Housing Authority and certain environmental organizations, related to alleged violations of the CAAat the Albany Terminal, particularly with respect to crude oil operations at the Albany Terminal. The October NOI revises the superseded and replaced September NOI to add two additional environmental advocacy organizations and to revise the relief sought and the description of the alleged CAA violations.

On February 3, 2016, Earthjustice and the other entities identified in the October NOI filed suit against the Partnership in federal court in Albany under the citizen suit provisions of the CAA. In summary, this lawsuit alleges that the Partnership’s operations at the Albany Terminal are in violation of the CAA. The plaintiffs seek, among other things, relief that would compel the Partnership both to apply for what they contend is the applicable permit under the CAA, and to install additional pollution controls. In addition, the plaintiffs seek to prohibit the Albany Terminal from receiving, storing, handling, and marine loading certain types of Bakken crude oil and to require payment of a civil penalty of $37,500 for each day the Partnership as operated the Albany Terminal in violation of the CAA. The Partnership believes that it has meritorious defenses against all allegations and will vigorously contest this lawsuit.

On May 29, 2015 and in connection with a commercial dispute with Tethys Trading Company LLC (“Tethys”), the Partnership received a notice from Tethys alleging a default under, and purporting to terminate, the Partnership’s contract with Tethys for crude oil services at the Partnership’s Oregon facility. However, the Partnership does not believe Tethys had the right to terminate the contract, and the Partnership will take appropriate action to enforce its rights under the agreement. The Partnership had expected to receive fees from this contract of approximately $13.2 million for the period July 1, 2015 through December 31, 2015 and approximately $105.2 million in the aggregate for the remaining four years of the contract.

On March26, 2015, the Partnership received a Notice of Non-Compliance (“NON”) from the Massachusetts Department of Environmental Protection (“DEP”) with respect to the Revere Terminal, alleging certain violations of the National Pollutant Discharge Elimination System Permit (“NPDES Permit”) related to storm water discharges. The NON requires the Partnership to submit a plan to remedy the reported violations of the NPDES Permit. The Partnership has responded to the NON with a plan and is implementing modifications to the storm water management system at the Revere Terminal. The Partnership has determined that compliance with the NON and implementation of the plan will have no material impact on its operations.

The Partnership has a dispute with Lansing Ethanol Services, LLC (“Lansing”) for damages in excess of $12.0million. The dispute involves Lansing’s failure to transfer Renewable Fuel Identification Numbers to the Partnership in connection with certain agreements for the purchase and sale of ethanol. The parties have agreed to arbitrate under the rules of the American Arbitration Association. The Partnership filed for arbitration on March24, 2015 and anticipates arbitration to commence during the first quarter ending March31, 2016. The Partnership believes it has meritorious positions and intends to vigorously pursue a favorable result in connection with this dispute.

On July 2, 2014, a lawsuit was filed by the Northwest Environmental Defense Center and other environmental

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

non-government organizations (the “Plaintiffs”) against the Partnership and Cascade Kelly alleging violations of the CAA. The suit, filed in the United States District Court for the district of Oregon, alleged that Cascade Kelly was operating without the proper permit under the applicable rules. The lawsuit sought penalties, injunctive relief and reimbursement of attorneys’ fees. A trial was held during the fourth quarter of 2015. On December 30, 2015, the Court issued a judgment in the Partnership’s favor and dismissed the case with prejudice. The time for requesting an appeal has passed and the Plaintiffs did not appeal. Accordingly, the case is closed.

On May 16, 2014, the Partnership received a subpoena from the SEC requesting information for relevant time periods primarily relating to the Partnership’s accounting for RINs and the restatements of its consolidated financial statements as of and for the quarters ended March31, 2013, June30, 2013 and September30, 2013. The Partnership intends to continue to cooperate fully with, and has produced responsive materials to, the SEC.

The Partnership received letters from the EPA dated November 2, 2011 and March 29, 2012, containing requirements and testing orders (collectively, the “Requests for Information”) for information under the CAA. The Requests for Information were part of an EPA investigation to determine whether the Partnership has violated sections of the CAA at certain of its terminal locations in New England with respect to residual oil and asphalt. On June6, 2014, a Notice of Violation (“NOV”) was received from the EPA, alleging certain violations of its Air Emissions License issued by the Maine Department of Environmental Protection, based upon the test results at the South Portland, Maine terminal. The Partnership met with and provided additional information to the EPA with respect to the alleged violations. On April 7, 2015, the EPA issued a Supplemental Notice of Violation (the “Supplemental NOV”) modifying the allegations of violations of the terminal’s Air Emissions License. The Partnership has responded to the Supplemental NOV and is engaged in further negotiations with the EPA. A tolling agreement was executed with the United States on December 1, 2015, and negotiations are continuing in the first quarter of 2016. The Partnership does not believe that a material violation has occurred, and it contests the allegations presented in the NOV and Supplemental NOV.The Partnership does not believe any adverse determination in connection with the NOV would have a material impact on its operations.

Note 21. 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, 2015
Sales	$	2,979,116	$	2,680,088	$	2,486,203	$	2,169,445	$	10,314,852
Gross profit (1)	$	168,558	$	144,188	$	152,299	$	132,624	$	597,669
Net income (loss) (1)(2)(3)	$	30,409	$	7,614	$	8,146	$	(2,905)	$	43,264
Net income (loss) attributable to Global Partners LP	$	30,415	$	7,218	$	8,212	$	(2,282)	$	43,563
Limited partners’ interest in net income (loss)	$	28,236	$	4,547	$	5,380	$	(2,267)	$	35,896
Basic net income (loss) per limited partner unit	$	0.92	$	0.15	$	0.16	$	(0.70)	$	1.12
Diluted net income (loss) per limited partner unit	$	0.92	$	0.15	$	0.16	$	(0.70)	$	1.11
Cash distributions per limited partner unit (5)	$	0.6650	$	0.6800	$	0.6925	$	0.6975	$	2.74

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	First		Second		Third		Fourth		Total
Year ended December 31, 2014
Sales	$	5,116,928	$	4,569,620	$	4,050,458	$	3,532,948	$	17,269,954
Gross profit (4)	$	159,024	$	87,685	$	155,435	$	142,643	$	544,787
Net income (loss) (2)(4)	$	57,154	$	(12,278)	$	43,622	$	28,482	$	116,980
Net income (loss) attributable to Global Partners LP	$	57,010	$	(12,719)	$	42,508	$	27,910	$	114,709
Limited partners’ interest in net (loss) income	$	55,502	$	(13,752)	$	40,885	$	26,093	$	108,728
Basic net income (loss) per limited partner unit	$	2.04	$	(0.50)	$	1.50	$	0.93	$	3.97
Diluted net income (loss) per limited partner unit	$	2.03	$	(0.50)	$	1.50	$	0.93	$	3.95
Cash distributions per limited partner unit (5)	$	0.6125	$	0.6250	$	0.6375	$	0.6525	$	2.53

(1) Includes a $5.0 million charge related to a customer dispute in the first quarter of 2015.

(2) Includes the following charges in connection with the acquisition of Warren: (i)acquisition costs of $4.4 million and $1.0 million in the first and second quarters of 2015, respectively, and $1.7 million in the fourth quarter of 2014; and (ii) a restructuring charge of $2.3 million in the first quarter of 2015.

(3) Includes acquisition costs in connection with the acquisition of Capitol of $3.1 million and $0.1 million in the second and third quarters of 2015, respectively.

(4) Includes the reclass of loss on sale and disposition of assets within GDSO’s station operations product margin to operating expenses of $0.7million, $0.4million and $1.1million in the first, second and fourth quarters of 2014, respectively, to conform to the Partnership’s current presentation.

(5) Cash distributions declared in one calendar quarter are paid in the following calendar quarter.

Note 22. Subsequent Events

The Partnership has identified certain non-strategic owned or leasehold assets of the GDSO segment which could result in the sale of more than 100 sites. As the Partnership is still in the preliminary stages of evaluating its portfolio of assets, any assets identified for disposition have not met the criteria to be presented as held for sale as of December 31, 2015.

On February 16, 2016, the Partnership paid a cash distribution of approximately $15.8 million to its unitholders of record as of the close of business on February 10, 2016.

Note 23. Supplemental Guarantor Condensed Consolidating Financial Statements

The Partnership’s wholly-owned subsidiaries, other than GLP Finance, are guarantors of senior notes issued by the Partnership and GLP Finance. As such, the Partnership is subject to the requirements of Rule 3-10 of Regulation S-X of the SEC regarding financial statements of guarantors and issuers of registered guaranteed securities. The Partnership presents condensed consolidating financial information for its subsidiaries within the notes to consolidated financial statements in accordance with the criteria established for parent companies in the SEC’s Regulation S-X, Rule 3-10(d). The following condensed consolidating financial information presents the Condensed Consolidating Balance Sheets as of December 31, 2015 and 2014, the Condensed Consolidating Statements of Operations for the years ended December 31, 2015, 2014 and 2013 and the Condensed Consolidating Statements of Cash Flows for the years ended December 31, 2015, 2014 and 2013 of the Partnership’s 100% owned guarantor subsidiaries, the non-guarantor subsidiary and the eliminations necessary to arrive at the information for the Partnership on a consolidated basis. The principal elimination entries eliminate investments in subsidiaries and intercompany balances and transactions.

F-71

GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Condensed Consolidating Balance Sheet

December 31, 2015

(In thousands)

		Issuer	Non-
	Guarantor		Guarantor
	Subsidiaries		Subsidiary		Eliminations		Consolidated
Assets
Current assets:
Cash and cash equivalents	$	—	$	4,690	$	(3,574)	$	1,116
Accounts receivable, net		311,079		275		—		311,354
Accounts receivable - affiliates		2,745		746		(913)		2,578
Inventories		388,952		—		—		388,952
Brokerage margin deposits		31,327		—		—		31,327
Derivative assets		66,099		—		—		66,099
Prepaid expenses and other current assets		65,376		233		—		65,609
Total current assets		865,578		5,944		(4,487)		867,035
Property and equipment, net		1,203,251		39,432		—		1,242,683
Intangible assets, net		75,694		—		—		75,694
Goodwill		349,306		86,063		—		435,369
Other assets		42,894		—		—		42,894
Total assets	$	2,536,723	$	131,439	$	(4,487)	$	2,663,675
Liabilities and partners' equity
Current liabilities:
Cash overdraft	$	3,574	$	—	$	(3,574)	$	—
Accounts payable		303,242		539		—		303,781
Accounts payable - affiliates		746		167		(913)		—
Working capital revolving credit facility - current portion		98,100		—		—		98,100
Environmental liabilities - current portion		5,350		—		—		5,350
Trustee taxes payable		95,264		—		—		95,264
Accrued expenses and other current liabilities		59,742		586		—		60,328
Derivative liabilities		31,911		—		—		31,911
Total current liabilities		597,929		1,292		(4,487)		594,734
Working capital revolving credit facility - less current portion		150,000		—		—		150,000
Revolving credit facility		269,000		—		—		269,000
Senior notes		656,564		—		—		656,564
Environmental liabilities - less current portion		67,883		—		—		67,883
Financing obligation		89,790		—		—		89,790
Deferred tax liabilities		84,836		—		—		84,836
Other long-term liabilities		56,884		—		—		56,884
Total liabilities		1,972,886		1,292		(4,487)		1,969,691
Partners' equity
Global Partners LP equity		563,837		83,952		—		647,789
Noncontrolling interest		—		46,195		—		46,195
Total partners' equity		563,837		130,147		—		693,984
Total liabilities and partners' equity	$	2,536,723	$	131,439	$	(4,487)	$	2,663,675

F-72

GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Condensed Consolidating Balance Sheet

December 31, 2014

(In thousands)

	Issuer		Non-
	Guarantor		Guarantor
	Subsidiaries		Subsidiary		Eliminations		Consolidated
Assets
Current assets:
Cash and cash equivalents	$	2,560	$	2,678	$	—	$	5,238
Accounts receivable, net		456,423		1,307		—		457,730
Accounts receivable - affiliates		4,584		820		(1,501)		3,903
Inventories		336,813		—		—		336,813
Brokerage margin deposits		17,198		—		—		17,198
Derivative assets		83,826		—		—		83,826
Prepaid expenses and other current assets		53,681		634		—		54,315
Total current assets		955,085		5,439		(1,501)		959,023
Property and equipment, net		778,385		46,666		—		825,051
Intangible assets, net		45,870		3,032		—		48,902
Goodwill		68,015		86,063		—		154,078
Other assets		43,763		—		—		43,763
Total assets	$	1,891,118	$	141,200	$	(1,501)	$	2,030,817
Liabilities and partners' equity
Current liabilities:
Accounts payable	$	455,629	$	990	$	—	$	456,619
Accounts payable - affiliates		820		681		(1,501)		—
Line of credit		—		700		—		700
Environmental liabilities - current portion		3,101		—		—		3,101
Trustee taxes payable		105,744		—		—		105,744
Accrued expenses and other current liabilities		81,686		1,134		—		82,820
Derivative liabilities		58,507		—		—		58,507
Total current liabilities		705,487		3,505		(1,501)		707,491
Working capital revolving credit facility - less current portion		100,000		—		—		100,000
Revolving credit facility		133,800		—		—		133,800
Senior notes		360,096		—		—		360,096
Environmental liabilities - less current portion		34,462		—		—		34,462
Deferred tax liabilities		12,958		—		—		12,958
Other long-term liabilities		45,854		—		—		45,854
Total liabilities		1,392,657		3,505		(1,501)		1,394,661
Partners' equity
Global Partners LP equity		498,461		88,481		—		586,942
Noncontrolling interest		—		49,214		—		49,214
Total partners' equity		498,461		137,695		—		636,156
Total liabilities and partners' equity	$	1,891,118	$	141,200	$	(1,501)	$	2,030,817

F-73

GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Condensed Consolidating Statement of Operations

For the Year Ended December 31, 2015

(In thousands)

			Non-
	Guarantor		Guarantor
	Subsidiaries		Subsidiary		Eliminations		Consolidated
Sales	$	10,306,493	$	23,549	$	(15,190)	$	10,314,852
Cost of sales		9,722,340		10,033		(15,190)		9,717,183
Gross profit		584,153		13,516		—		597,669
Costs and operating expenses:
Selling, general and administrative expenses		174,925		2,118		—		177,043
Operating expenses		281,201		9,106		—		290,307
Amortization expense		10,467		3,032		—		13,499
Loss on sale and disposition of assets		2,097		—		—		2,097
Total costs and operating expenses		468,690		14,256		—		482,946
Operating income (loss)		115,463		(740)		—		114,723
Interest expense		(73,324)		(8)		—		(73,332)
Income (loss) before income tax expense		42,139		(748)		—		41,391
Income tax expense		1,873		—		—		1,873
Net income (loss)		44,012		(748)		—		43,264
Net loss attributable to noncontrolling interest		—		299		—		299
Net income (loss) attributable to Global Partners LP		44,012		(449)		—		43,563
Less: General partner's interest in net income, including incentive distribution rights		7,667		—		—		7,667
Limited partners' interest in net income (loss)	$	36,345	$	(449)	$	—	$	35,896

F-74

GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Condensed Consolidating Statement of Operations

For the Year Ended December 31, 2014

(In thousands)

			Non-
	Guarantor		Guarantor
	Subsidiaries		Subsidiary		Eliminations		Consolidated
Sales	$	17,256,583	$	39,347	$	(25,976)	$	17,269,954
Cost of sales		16,743,163		7,980		(25,976)		16,725,167
Gross profit		513,420		31,367		—		544,787
Costs and operating expenses:
Selling, general and administrative expenses		150,964		2,997		—		153,961
Operating expenses		192,512		11,558		—		204,070
Amortization expense		7,846		11,021		—		18,867
Loss on sale and disposition of assets		2,182		—		—		2,182
Total costs and operating expenses		353,504		25,576		—		379,080
Operating income (loss)		159,916		5,791		—		165,707
Interest expense		(47,651)		(113)		—		(47,764)
Income (loss) before income tax expense		112,265		5,678		—		117,943
Income tax expense		(963)		—		—		(963)
Net income		111,302		5,678		—		116,980
Net (income) loss attributable to noncontrolling interest		—		(2,271)		—		(2,271)
Net income attributable to Global Partners LP		111,302		3,407		—		114,709
Less: General partner's interest in net income, including incentive distribution rights		5,981		—		—		5,981
Limited partners' interest in net income	$	105,321	$	3,407	$	—	$	108,728

F-75

GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Condensed Consolidating Statement of Operations

For the Year Ended December 31, 2013

(In thousands)

			Non-
	Guarantor		Guarantor
	Subsidiaries		Subsidiaries		Eliminations		Consolidated
Sales	$	19,575,042	$	28,948	$	(14,382)	$	19,589,608
Cost of sales		19,194,385		5,049		(14,382)		19,185,052
Gross profit		380,657		23,899		—		404,556
Costs and operating expenses:
Selling, general and administrative expenses		110,228		5,263		—		115,491
Operating expenses		175,284		10,429		—		185,713
Amortization expense		7,106		12,110		—		19,216
Gain on sale and disposition of assets		(1,273)		—		—		(1,273)
Total costs and operating expenses		291,345		27,802		—		319,147
Operating income (loss)		89,312		(3,903)		—		85,409
Interest expense		(43,536)		(1)		—		(43,537)
Income (loss) before income tax expense		45,776		(3,904)		—		41,872
Income tax expense		(819)		—		—		(819)
Net income (loss)		44,957		(3,904)		—		41,053
Net loss attributable to noncontrolling interest		—		1,562		—		1,562
Net income (loss) attributable to Global Partners LP		44,957		(2,342)		—		42,615
Less: General partner's interest in net income, including incentive distribution rights		3,521		—		—		3,521
Limited partners' interest in net income	$	41,436	$	(2,342)	$	—	$	39,094

F-76

GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Condensed Consolidating Statement of Cash Flows

For the Year Ended December 31, 2015

(In thousands)

	(Issuer)		Non-
	Guarantor		Guarantor
	Subsidiaries		Subsidiary		Consolidated
Cash flows from operating activities
Net cash provided by operating activities	$	50,309	$	12,197	$	62,506
Cash flows from investing activities
Acquisitions		(561,170)		—		(561,170)
Capital expenditures		(90,240)		(2,685)		(92,925)
Proceeds from sale of property and equipment		4,331		—		4,331
Net cash used in investing activities		(647,079)		(2,685)		(649,764)
Cash flows from financing activities
Proceeds from issuance of common units, net		109,305		—		109,305
Borrowings from working capital revolving credit facility		148,100		—		148,100
Borrowings from revolving credit facility		135,200		—		135,200
Proceeds from senior notes, net of discount		295,338		—		295,338
Payments on line of credit		—		(700)		(700)
Repurchase of common units		(3,892)		—		(3,892)
Noncontrolling interest capital contribution		9,360		(6,800)		2,560
Distribution to noncontrolling interest		(5,280)		—		(5,280)
Distributions to partners		(97,495)		—		(97,495)
Net cash provided by (used in) financing activities		590,636		(7,500)		583,136
Cash and cash equivalents
(Decrease) increase in cash and cash equivalents		(6,134)		2,012		(4,122)
Cash and cash equivalents at beginning of year		2,560		2,678		5,238
Cash and cash equivalents at end of year	$	(3,574)	$	4,690	$	1,116

F-77

GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Condensed Consolidating Statement of Cash Flows

For the Year Ended December 31, 2014

(In thousands)

	(Issuer)		Non-
	Guarantor		Guarantor
	Subsidiaries		Subsidiary		Consolidated
Cash flows from operating activities
Net cash provided by operating activities	$	321,319	$	23,583	$	344,902
Cash flows from investing activities
Capital expenditures		(78,863)		(16,251)		(95,114)
Proceeds from sale of property and equipment		4,021		—		4,021
Net cash used in investing activities		(74,842)		(16,251)		(91,093)
Cash flows from financing activities
Proceeds from public offering, net		137,844		—		137,844
Payments on working capital revolving credit facility		(227,000)		—		(227,000)
Payments on revolving credit facility		(300,900)		—		(300,900)
Payments on line of credit		—		(3,000)		(3,000)
Proceeds from senior notes, net of discount		258,903		—		258,903
Repayment of senior notes		(40,244)		—		(40,244)
Repurchase of common units		(8,632)		—		(8,632)
Noncontrolling interest capital contribution		10,700		(2,500)		8,200
Distribution to noncontrolling interest		(9,200)		—		(9,200)
Distributions to partners		(73,759)		—		(73,759)
Net cash used in financing activities		(252,288)		(5,500)		(257,788)
Cash and cash equivalents
(Decrease) increase in cash and cash equivalents		(5,811)		1,832		(3,979)
Cash and cash equivalents at beginning of year		8,371		846		9,217
Cash and cash equivalents at end of year	$	2,560	$	2,678	$	5,238

F-78

GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Condensed Consolidating Statement of Cash Flows

For the Year Ended December 31, 2013

(In thousands)

	(Issuer)		Non-
	Guarantor		Guarantor
	Subsidiaries		Subsidiary		Consolidated
Cash flows from operating activities
Net cash provided by operating activities	$	240,699	$	14,448	$	255,147
Cash flows from investing activities
Acquisitions		(94,179)		(91,083)		(185,262)
Capital expenditures		(53,484)		(13,648)		(67,132)
Proceeds from sale of property and equipment		9,179		8		9,187
Net cash used in investing activities		(138,484)		(104,723)		(243,207)
Cash flows from financing activities
Payments on working capital revolving credit facility		(97,500)		—		(97,500)
Borrowings from revolving credit facility		12,700		—		12,700
Proceeds from issuance of term loan		115,000		—		115,000
Repayment of term loan		(115,000)		—		(115,000)
Borrowings from line of credit		—		3,700		3,700
Proceeds from senior notes, net of discount		147,900		—		147,900
Repurchase of common units		(4,590)		—		(4,590)
Repurchased units withheld for tax obligations		(2,086)		—		(2,086)
Noncontrolling interest capital contribution		(85,996)		87,421		1,425
Distribution to noncontrolling interest		(2,920)		—		(2,920)
Distributions to partners		(67,329)		—		(67,329)
Net cash used in (provided by) financing activities		(99,821)		91,121		(8,700)
Cash and cash equivalents
Increase in cash and cash equivalents		2,394		846		3,240
Cash and cash equivalents at beginning of year		5,977		—		5,977
Cash and cash equivalents at end of year	$	8,371	$	846	$	9,217

F-79

Item 15(a)

SCHEDULE II—VALUATION AND QUALIFYING ACCOUNTS

GLOBAL PARTNERS LP

FOR THE YEARS ENDED DECEMBER 31, 2015, 2014 and 2013

(In thousands)

	Balance at		Charged to								Balance
	Beginning		Costs and						Other		at End
Description	of Period		Expenses		Recoveries		Write Offs		Adjustment		of Period
Year ended December 31,  2015
Allowance for doubtful accounts—accounts receivable	$	4,818	$	1,303	$	42	$	(1,297)	$	1,076	$	5,942
Year ended December 31,  2014
Allowance for doubtful accounts—accounts receivable	$	7,513	$	1,700	$	277	$	(4,672)	$	—	$	4,818
Year ended December 31,  2013
Allowance for doubtful accounts—accounts receivable	$	5,131	$	4,145	$	9	$	(1,772)	$	—	$	7,513

F-80

INDEX TO EXHIBITS

Exhibit Number		Description
2.1**	—	Stock Purchase Agreement, dated as of October 3, 2014, by and among Warren Equities, Inc., as the Company, The Warren Alpert Foundation, as the Seller, and Global Montello Group Corp., as Buyer, and Solely with Respect to Section 10.20 and the Other Provisions in Article 10 Related Thereto, Global Partners LP, as Buyer Guarantor (incorporated herein by reference to Exhibit 2.1 to the Current Report on Form 8‑K filed on October 9, 2014 (File No. 001‑32593)).
2.2	—	First Amendment to Stock Purchase Agreement dated as of December 12, 2014 by and among Warren Equities, Inc., as the Company, The Warren Alpert Foundation, as the Seller, and Global Montello Group Corp., as Buyer, and Global Partners LP, as Buyer Guarantor (incorporated herein by reference to Exhibit 2.2 to the Current Report on Form 8‑K filed on January 13, 2015 (File No. 001‑32593)).
2.3	—	Second Amendment to Stock Purchase Agreement dated as of January 7, 2015 by and among Warren Equities, Inc., as the Company, The Warren Alpert Foundation, as the Seller, and Global Montello Group Corp., as Buyer, and Global Partners LP, as Buyer Guarantor (incorporated herein by reference to Exhibit 2.3 to the Current Report on Form 8‑K filed on January 13, 2015 (File No. 001‑32593)).
2.4**	—	Agreement of Purchase and Sale dated as of January 14, 2015 between Global Revco Dock, L.L.C, Global Revco Terminal, L.L.C., Global South Terminal, L.L.C., Global Petroleum Corp. and Global Companies LLC (incorporated herein by reference to Exhibit 2.1 to the Current Report on Form 8‑K filed on January 21, 2015 (File No. 001‑32593)).
2.5**	—	Sale And Purchase Agreement, dated as of April 9, 2015, by and among Liberty Petroleum Realty, LLC, East River Petroleum Realty, LLC, Big Apple Petroleum Realty, LLC, White Oak Petroleum, LLC, Anacostia Realty, LLC, Mount Vernon Petroleum Realty, LLC and DAG Realty, LLC, as Seller and Global Partners LP, as Buyer (incorporated herein by reference to Exhibit 2.1 to the Current Report on Form 8-K filed on April 15, 2015).
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).

4.6	—	Supplemental Indenture—Subsidiary Guarantee, dated as of March 5, 2013, by and among Global Partners LP and GLP Finance Corp., as Issuers and the Guarantors party thereto (incorporated herein by reference to Exhibit 4.2 to the Quarterly Report on Form 10‑Q filed on May 9, 2014).
4.7	—	Indenture, dated as of June 24, 2014, among the Issuers, the Guarantors, and Deutsche Bank Trust Company Americas, as trustee (incorporated herein by reference to Exhibit 4.1 to the Current Report on Form 8‑K filed on June 25, 2014).
4.8	—	Registration Rights Agreement, dated June 24, 2014, among the Issuers, the Guarantors and the Initial Purchasers (incorporated herein by reference to Exhibit 4.2 to the Current Report on Form 8‑K filed on June 25, 2014).
4.9	—	Indenture, dated as of June 4, 2015, among the Issuers, the Guarantors, and Deutsche Bank Trust Company Americas, as trustee (incorporated herein by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on June 4, 2015).
4.10	—	Registration Rights Agreement, dated June 4, 2015, among the Issuers, the Guarantors and the Initial Purchasers (incorporated herein by reference to Exhibit 4.2 to the Current Report on Form 8-K filed on June 4, 2015).
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	—	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).
10.4	—	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).
10.5^	—	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).
10.6	—	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).
10.7	—	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).
10.8	—	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).
10.9††	—	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).
10.10	—	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).
10.11	—	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).

10.12^	—	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).
10.13	—	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).
10.14	—	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).
10.15^	—	Global 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).
10.16^	—	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).
10.17^	—	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).
10.18^	—	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).
10.19^	—	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).
10.20^	—	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).
10.21^	—	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).
10.22^	—	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).
10.23^	—	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).
10.24	—	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).

10.25††	—	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 (incorporated herein by reference to Exhibit 10.52 to the Annual Report on Form 10‑K filed on April 1, 2014).
10.26	—	Purchase Agreement, dated June 19, 2014 among the Issuers, the Guarantors and the Initial Purchasers (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8‑K filed on June 25, 2014).
10.27	—	Exchange Rights Agreement, dated June 19, 2014 by and among Global Partners LP, GLP Finance Corp. and FS Energy and Power Fund (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8‑K filed on June 25, 2014).
10.28	—	Exchange Rights Agreement, dated June 19, 2014 by and among Global Partners LP. GLP Finance Corp., FS Energy and Power Fund, Kayne Anderson Non‑Traditional Investments, L.P., Kanti (QP), L.P., Kayne Anderson Capital Income Partners (QP), L.P., Kayne Anderson Income Partners, L.P., Kayne Anderson Infrastructure Income Fund, L.P., Kayne Energy Credit Opportunities, L.P. and Karbo L.P. (incorporated herein by reference to Exhibit 10.3 to the Current Report on Form 8‑K filed on June 25, 2014).
10.29	—	First Amendment to Second Amended and Restated Credit Agreement dated October 6, 2014 (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8‑K filed on October 9, 2014).
10.30	—	Second Amendment to Second Amended and Restated Credit Agreement dated October 20, 2014 (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8‑K filed on October 24, 2014).
10.31^	—	Employment Agreement dated December 31, 2014, 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, 2015).
10.32^	—	Employment Agreement dated December 31, 2014, 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 7, 2015).
10.33^	—	Employment Agreement by and between Global GP LLC and Andrew P. Slifka, dated as of January 22, 2015 (incorporated herein by reference to Exhibit 10.45 to the Annual Report on Form 10‑K filed on March 13, 2015).
10.34^	—	Form of Director Unit Award Letter (incorporated herein by reference to Exhibit 10.46 to the Annual Report on Form 10‑K filed on March 13, 2015).
10.35^	—	Form of Canadian Grant Agreement (incorporated herein by reference to Exhibit 10.47 to the Annual Report on Form 10‑K filed on March 13, 2015).
10.36	—	Amended and Restated Services Agreement, dated as of March 11, 2015, by and between AE Holdings Corp. and Global Companies LLC (incorporated herein by reference to Exhibit 10.48 to the Annual Report on Form 10‑K filed on March 13, 2015).
10.37	—	Second Amended and Restated Services Agreement, dated as of March 11, 2015, by and among Global Petroleum Corp. and Global Companies LLC (incorporated herein by reference to Exhibit 10.49 to the Annual Report on Form 10‑K filed on March 13, 2015).
10.38	—	Third Amendment to Second Amended and Restated Credit Agreement dated April 27, 2015 (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8‑K filed on April 30, 2015).

10.39	—	Purchase Agreement, dated June 1, 2015 among the Issuers, the Guarantors and the Initial Purchasers (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8‑K filed on June 4, 2015).
10.40^	—	Form of Restricted Unit Award Grant Letter (incorporated herein by reference to Exhibit 10.2 to the Quarterly Report on Form 10‑Q filed on August 7, 2015).
10.41^	—	Form of Cash Award Grant Letter (incorporated herein by reference to Exhibit 10.3 to the Quarterly Report on Form 10‑Q filed on August 7, 2015).
10.42^	—	Form of Canadian Grant Agreement (incorporated herein by reference to Exhibit 10.4 to the Quarterly Report on Form 10‑Q filed on August 7, 2015).
10.43^	—	Form of Phantom Unit Agreement (Cash Settlement) (incorporated herein by reference to Exhibit 10.1 to the Quarterly Report on Form 10‑Q filed on November 6, 2015).
10.44^	—	Employment Agreement dated November 1, 2015, by and between Global GP LLC and DaphneH. Foster (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8‑K filed on November 10, 2015).
10.45^	—	Employment Agreement dated November 1, 2015, by and between Global GP LLC and Mark Romaine (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8‑K filed on November 10, 2015).
10.46*	—	Fourth Amendment to Second Amended and Restated Credit Agreement dated December 18, 2015.
10.47*	—	Fifth Amendment to Second Amended and Restated Credit Agreement dated February 24, 2016.
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.

*Filed herewith.

^Management contract or compensatory plan or arrangement.

**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.

†Not deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934 or otherwise subject to the liability of that section.

††Portions of this exhibit have been omitted pursuant to an order granting confidential treatment, dated May 9, 2014 (SEC File No. 001-32593).  

EX-10.46

Exhibit 10.46

FOURTH AMENDMENT TO SECOND AMENDED AND RESTATED CREDIT AGREEMENT

This Fourth Amendment to Second Amended and Restated Credit Agreement(this "Fourth Amendment") is made as of December18, 2015, by and amongGLOBAL OPERATING LLC, a Delaware limited liability company ("OLLC"), GLOBAL COMPANIES LLC, a Delaware limited liability company ("Global"), GLOBAL MONTELLO GROUP CORP., a Delaware corporation ("Montello"), GLEN HES CORP., a Delaware corporation ("Glen Hes"), CHELSEA SANDWICH LLC, a Delaware limited liability company ("Chelsea LLC"), GLP FINANCE CORP., a Delaware corporation ("Finance"), GLOBAL ENERGY MARKETING LLC, a Delaware limited liability company ("GEM"), GLOBAL ENERGY MARKETING II LLC, a Delaware limited liability company ("GEM II"),  GLOBAL CNG LLC, a Delaware limited liability company ("CNG"), ALLIANCE ENERGY LLC, a Massachusetts limited liability company ("Alliance"),CASCADE KELLY HOLDINGS LLC, an Oregon limited liability company ("Cascade") and WARREN EQUITIES, INC., a Delaware corporation ("Warren" and, collectively with  OLLC, Global, Montello, Glen Hes, Chelsea LLC, Finance, GEM, GEM II, CNG, Alliance and Cascade, the "Borrowers" and each individually, a  "Borrower"), GLOBAL PARTNERS LP, a Delaware limited partnership (the "MLP"), each "Lender" (as such term is defined in the Credit Agreement referred to below) (collectively, the "Lenders" and each individually, a "Lender") party hereto, and Bank of America, N.A. as Administrative Agent (as such term is defined in the Credit Agreement), amending certain provisions of that certain Second Amended and Restated Credit Agreement dated as of December 16, 2013 (as amended and in effect from time to time, the "Credit Agreement") by and among the Borrowers, the MLP, the Lenders, the Administrative Agent, Swing Line Lender, the L/C Issuer, the Alternative Currency Fronting Lender, JPMorgan Chase Bank, N.A. and Wells Fargo Bank, N.A. as Co-Syndication Agents and RBS Citizens NA and Societe Generale, as Co-Documentation Agents.  Capitalized terms used herein without definition and which are defined in the Credit Agreement shall have the same respective meanings herein as therein.

WHEREAS, the Loan Parties, the requisite Lenders andthe Administrative Agentdesire to amend certain provisions of the Credit Agreement, all as provided more fully herein below;

NOW, THEREFORE, in consideration of the premises and the mutual agreements contained herein and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto hereby agree as follows:

§1.      Amendment to Section 1 of the Credit Agreement.Section 1.01 of the Credit Agreement is hereby amended as follows:

(a)       The definition of "AR Buyer" contained in Section 1.01 of the Credit Agreement is hereby amended by deleting such definition it its entirety and restating it as follows:

"AR Buyer" means any Person that is a party to a Receivables Sales Agreement as the buyer of the Accounts Receivable being sold thereunder.  

(b)       The definition of "Borrowing Base" contained in Section 1.01 of the Credit Agreement is hereby amended by deleting clause (c) of such definition and restating clause (c) as follows:

(c)90% of Insured Eligible Receivables not included in Major Oil Company Receivables and 85% of Eligible Receivables which are not Insured Eligible Receivables and which are not included in Major Oil Company Receivables;  plus

(c)     The definition of "Eligible Receivables" contained in Section 1.01 of the Credit Agreement is hereby amended by deleting the last paragraph of such definition which appears immediately after clause (i) of such definition and restating such paragraph as follows:

For the purpose of this definition, (i) to the extent that Eligible Receivables owing by any obligor and its Affiliates, other than Exxon Mobil Corp. ("Exxon"), Phillips 66 ("P66") and an obligor of an Insured Eligible Receivable with respect to such Insured Eligible Receivable,exceed fifteen percent (15%) of the aggregate amount of all Eligible Receivables, or, in the case of Exxon, P66 and an obligor of an Insured Eligible Receivable with respect to such Insured Eligible Receivable, exceeds twenty five percent (25%) of the aggregate amount of all Eligible Receivables, such excess shall not be included in the calculation of Eligible Receivables without the prior written consent of the Required Lenders, or as otherwise provided in the definition of Major Oil Company Receivables, and (ii) to the extent that the Borrowers, individually or in the aggregate, are at any time directly or contingently indebted for any reason to any obligor, the Accounts Receivable owing to the Borrowers by such obligor shall be deemed to be subject to an offset, counterclaim or contra in the amount of such indebtedness; provided,  however, to the extent that any indebtedness of the Borrowers to any obligor is secured by a Letter of Credit, the portion of the indebtedness so secured (not to exceed the amount available for drawing under the Letter of Credit) shall not be deemed to be an offset, counterclaim or contra with respect to the accounts receivable of such obligor owing to the Borrowers.

(d)       The definition of "Receivables Intercreditor Agreement" contained in Section 1.01 of the Credit Agreement is hereby amended by deleting such definition in its entirety and restating such definition as follows:

"Receivables Intercreditor Agreement" means any intercreditor agreement to be entered into among the Administrative Agent at the Administrative Agent's request, the applicable Loan Party and the applicable AR Buyer with respect to any applicable AR Sales Transaction where the Administrative Agent requests such an agreement, such agreement to be in form and substance satisfactory to the Administrative Agent.

(e)       Section 1.01 of the Credit Agreement is further amended by inserting the following definitions in the appropriate alphabetical order:

"Insured Eligible Receivable"  means any Eligible Receivable the payment of which is insured by an insurance company with a rating of not less than "A"

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from at least two (2) rating services acceptable to the Administrative Agent (such as A.M. Best Company, Inc., Fitch Ratings, Moody's Investor Services or Standard & Poor's Insurance Ratings Services), with the Administrative Agent being named as loss payee and additional insured thereunder, and the terms, conditions and coverage of such insurance is acceptable to the Administrative Agent. To the extent only a portion of the payment with respect to any Eligible Receivable is so insured in accordance with the terms of this definition, only the portion so insured shall constitute an Insured Eligible Receivable.

"Leasehold Interest EBITDA"  means, with respect to any Subject Leasehold Interest at the time such interest is acquired by the applicable Loan Party, an amount reasonably determined by the Loan Parties to be the expected earnings before interest, taxes, depreciation and amortization, on an annualized basis, for such Subject Leasehold Interest.

"Subject Leasehold Interest"  has the meaning set forth in Section 6.13(b) hereof.

§2.      Amendment to Section 6.13 of the Credit Agreement.Section 6.13 of the Credit Agreement is hereby amended by deleting Section 6.13 in its entirety and restating it as follows:

6.13   Additional Borrowers or Subsidiary Guarantors; Additional Assets.(a)   Notify the Administrative Agent at the time that any Person becomes a Subsidiary, and, promptly thereafter (and in any event within thirty (30) days), cause (i) such Person, if such Person is a Domestic Subsidiary or a Foreign Subsidiary which would not suffer any adverse tax consequence as a result thereof, to become a Borrower or Guarantor (with a Foreign Subsidiary being required to be a Guarantor hereunder and being subject to the Administrative Agent's consent) hereunder by executing and delivering to the Administrative Agent a joinder to this Agreement and the other Loan Documents (including, without limitation, the Security Documents) or such other document as the Administrative Agent shall deem appropriate for such purpose (including, without limitation, any document necessary to grant to the Administrative Agent, for the benefit of the Secured Parties, a first priority perfected security interest in such Domestic Subsidiary's assets), (ii) such Person, if such Person is a Domestic Subsidiary or a Foreign Subsidiary which would not suffer any adverse tax consequence as a result thereof, to deliver to the Administrative Agent documents of the types referred to in clauses (iii) and (iv) of Section 4.01(a) and favorable opinions of counsel to such Person (which shall cover, among other things, the legality, validity, binding effect and enforceability of the documentation referred to in clause (i)), all in form, content and scope reasonably satisfactory to the Administrative Agent; (iii)  Schedule 5.13 hereto to be updated to give effect to any changes resulting from the formation or acquisition of such new Subsidiary.

(b)Except as expressly provided for otherwise herein, each Loan Party has granted to the Administrative Agent, for the benefit of the Administrative Agent and the other Secured Parties, a lien on substantially all of such Loan Party's assets as set forth in the Security Documents.  In furtherance of

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the foregoing, in connection with property that becomes property owned by a Loan Party after the Closing Date for which a Lien on such property is required by the terms of the Security Documents, or if any Loan Party acquires any fee or leasehold interest in any Real Estate after the Closing Date, other than (i) any leasehold interests in any property acquired in any Permitted Acquisition or otherwise permitted pursuant to Section 7.06 hereof for which the Loan Parties have used commercially reasonable efforts to obtain but for which the owner of such property will not consent to such leasehold mortgage (in which case such leasehold mortgage will not be required) and(ii) the leasehold interests of those sites located in New York, Maryland or another jurisdiction subject to a mortgage recording tax and, in all casesacquired pursuant to, and which are the subject of, the Unitary Lease, the Project Monument Unitary Lease and the Project Oak Unitary Lease, the applicable Loan Party shall deliver (A) such documentation as the Administrative Agent may reasonably deem necessary or desirable in order to create and perfect and obtain the full benefits of such Lien, including mortgages, deeds of trust, security agreements, UCC-1 financing statements, surveys, real estate title insurance policies, certified resolutions and other organizational and authorizing documents of the grantor of liens, favorable opinions of the general counsel of the applicable Loan Party (which shall cover, among other things, the legality, validity, binding effect and enforceability of the documentation referred to above and the perfection of the Administrative Agent’s Liens thereunder) and other items of the types required to be delivered pursuant to Section 4.01, all in form, content and scope reasonably satisfactory to the Administrative Agent, and (B) such other documentation as the Required Lenders may reasonably deem necessary or desirable in order to create and perfect and obtain the full benefits of such Lien.  Notwithstanding anything to the contrary contained herein, to the extent any Loan Party acquires a leasehold interest in any Real Estate that a Loan Party would otherwise be required to provide a leasehold mortgage with respect thereto pursuant to the provisions of this Section 6.13 (each, a "Subject Leasehold Interest"), the applicable Loan Party shall not be required to provide such a leasehold mortgage and related documentation with respect to such Subject Leasehold Interest so long as (a) at the time of acquiring such Subject Leasehold Interest (or, for any such Subject Leasehold Interest acquired prior to December 18, 2015, on December 18, 2015)the Loan Parties have provided to the Administrative Agent written notice of their intention to not provide such a leasehold mortgage and related documentation on the Subject Leasehold Interest, together with the Loan Parties' determination of the Leasehold Interest EBITDA with respect to such Subject Leasehold Interest (and which Leasehold Interest EBITDA determination shall be acceptable to the Administrative Agent in its reasonable judgment); and (b) the aggregate Leasehold Interest EBITDA on all Subject Leasehold Interests which are not subject to a leasehold mortgage does not exceed, in the aggregate, $25,000,000 at any time.  The Loan Parties shall at any time be permitted to provide the Administrative Agent with a leasehold mortgage and the other documents required in connection therewith on any Subject Leasehold Interest so as to maintain its compliance with clause (b) of the immediately preceding sentence.

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§3.      Amendment to Section 7.02 of the Credit Agreement.  Section 7.02(l)(i) of the Credit Agreement is hereby amended by deleting Section 7.01(l)(i) and restating it as follows:  "(i)  sites leased or subleased, as the case may be, by a Loan Party under the Unitary Lease, the proceeds of which will be used to make improvements on such sites;".

§4.      Amendment to Section 7.05 of the Credit Agreement.  Section 7.05(h) of the Credit Agreement is hereby amended by deleting Section 7.05(h) in its entirety and restating it as follows:

(h)      Dispositions of Accounts Receivable to an AR Buyer to the extent that (i) no Default or Event of Default has occurred and is continuing or would exist after giving effect to any such Disposition; (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 shall not be 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 (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 shall not be less than 85% of the face amount of such Account Receivable); (iv) such Account Receivable shall be sold pursuant to a Receivables Sales Agreement, a copy of which has been provided to the Administrative Agent and, to the extent required by the Administrative Agent, the AR Sales Transaction shall be subject to an Receivables Intercreditor Agreement (which, if required by the Administrative Agent, shall be entered into prior to any sale being made); (v) the Loan Parties have complied with the notice requirement set forth in Section 6.02 hereof; (vi) neither the AR Buyer nor the Administrative Agent has delivered any notice of a termination event under the terms of the Receivables Intercreditor Agreement; (vii) the aggregate amount of the Open Receivables Amount (after giving effect to all sales) shall not exceed $75,000,000 at any time; and (viii) the cash proceeds received from the applicable Loan Party in connection with such sale shall be used to immediately repay any outstanding WC Loans (such Dispositions made in compliance with the terms hereof being hereinafter referred to as a "Permitted Receivable Sale");

§5.Conditions to Effectiveness. This Fourth Amendment, other than the changes in Section 1 hereof to the definitions of "Borrowing Base" and "Eligible Receivables" and the addition of the term "Insured Eligible Receivables", will become effective as of the date hereof upon receipt by the Administrative Agent of the fully executed original counterparts of this Fourth Amendment executed by the Loan Parties, the Administrative Agent and the RequiredLenders, and the changes in Section 1 hereof to the definitions of "Borrowing Base" and "Eligible Receivables" and the addition of the term "Insured Eligible Receivables", will only become effective as of the date hereof upon receipt by the Administrative Agent of the fully executed original counterparts of this Fourth Amendment executed by the Loan Parties, the Administrative Agent and the Supermajority Lenders.  To the extent the Administrative Agent receives fully executed original counterparts of this Fourth Amendment executed by the Loan Parties, the Administrative Agent and the Required Lenders but not the Supermajority Lenders, the only provisions of this Fourth Amendment which shall not be modified as set forth herein are the changes in Section 1 hereof to the definitions of "Borrowing Base" and "Eligible Receivables" and the

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addition of the term "Insured Eligible Receivables" and to the extent the Administrative Agent receives fully executed original counterparts of this Fourth Amendment executed by the Loan Parties, the Administrative Agent and the Supermajority Lenders, then all provisions of this Fourth Amendment shall be modified as set forth herein.

§6.Representations and Warranties; No Default.  Each of the Loan Parties hereby repeats, on and as of the date hereof, each of the representations and warranties made by it in Article V of the Credit Agreement, provided, that all references therein to the Credit Agreement shall refer to such Credit Agreement as amended hereby.  In addition, each of the Loan Parties hereby represents and warrants that the execution and delivery by such Loan Party of this Fourth Amendment and the performance by each such Loan Party of all of its agreements and obligations under the Credit Agreement as amended hereby and the other Loan Documents to which it is a party are within the corporate, partnership and/or limited liability company authority of each of the Loan Parties and have been duly authorized by all necessary corporate, partnership and/or membership action on the part of each of the Loan Parties.  Each of the Loan Parties hereby certifies to the Administrative Agent and the Lenders that no Default or Event of Default has occurred and is continuing as of the date hereof.

§7.Ratification,  Etc.  Except as expressly amended hereby, the Credit Agreement and all documents, instruments and agreements related thereto, including, but not limited to the Security Documents, are hereby ratified and confirmed in all respects and shall continue in full force and effect.  The Credit Agreement and this Fourth Amendment shall be read and construed as a single agreement.  All references in the Credit Agreement or any related agreement or instrument to the Credit Agreement shall hereafter refer to the Credit Agreement as amended hereby.  This Fourth Amendment shall constitute a Loan Document.

§8.No Waiver.Nothing contained herein shall constitute a waiver of, impair or otherwise affect any Obligations, any other obligation of the Loan Parties or any rights of the Administrative Agent, the L/C Issuer, the Swing Line Lender, the Alternative Currency Fronting Lender, the Syndication Agent, the Co-Documentation Agents or the Lenders consequent thereon.

§9.Counterparts.  This Fourth Amendment may be executed in one or more counterparts, each of which shall be deemed an original but which together shall constitute one and the same instrument.Delivery of an executed counterpart of a signature page of this Agreement by facsimile or other electronic imaging means (e.g. "pdf" or "tif") shall be effective as delivery of a manually executed counterpart of this Agreement.

§10.Governing Law.THIS FOURTH AMENDMENT SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK.

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IN WITNESS WHEREOF, the parties hereto have executed this Fourth Amendment as a document under seal as of the date first above written.

GLOBAL OPERATING LLC
By:	Global Partners LP, its sole member
By:	Global GP LLC, its general partner
By:	/s/Daphne H. Foster
	Title:  Chief Financial Officer
GLOBAL COMPANIES LLC
By:	Global Operating LLC, its sole member
By:	Global Partners LP, its sole member
By:	Global GP LLC, its general partner
By:	/s/Daphne H. Foster
	Title:  Chief Financial Officer
GLOBAL MONTELLO GROUP CORP.
By:	/s/Daphne H. Foster
	Title: Chief Financial Officer
CHELSEA SANDWICH LLC
By:	Global Operating LLC, its sole member
By:	Global Partners LP, its sole member
By:	Global GP LLC, its general partner
By:	/s/Daphne H. Foster
	Title:  Chief Financial Officer
GLEN HES CORP.
By:	/s/Daphne H. Foster
	Title:  Chief Financial Officer

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GLP FINANCE CORP.
By:	/s/Daphne H. Foster
	Title:  Chief Financial Officer
GLOBAL ENERGY MARKETING LLC
By:	Global Operating LLC, its sole member
By:	Global Partners LP, its sole member
By:	Global GP LLC, its general partner
By:	/s/Daphne H. Foster
	Title:  Chief Financial Officer
GLOBAL ENERGY MARKETING II LLC
By:	Global Operating LLC, its sole member
By:	Global Partners LP, its sole member
By:	Global GP LLC, its general partner
By:	/s/Daphne H. Foster
	Title: Chief Financial Officer
ALLIANCE ENERGY LLC
By:	Global Operating LLC, its sole member
By:	Global Partners LP, its sole member
By:	Global GP LLC, its general partner
By:	/s/Daphne H. Foster
	Title:  Chief Financial Officer
CASCADE KELLY HOLDINGS LLC
By:	Global Operating LLC, its sole member
By:	Global Partners LP, its sole member
By:	Global GP LLC, its general partner
By:	/s/Daphne H. Foster
	Title:  Chief Financial Officer
GLOBAL CNG LLC

8

By:	Global Operating LLC, its sole member
By:	Global Partners LP, its sole member
By:	Global GP LLC, its general partner
By:	/s/Daphne H. Foster
	Title:  Chief Financial Officer
WARREN EQUITIES, INC.
By:	/s/Daphne H. Foster
	Title:  Chief Financial Officer
GLOBAL PARTNERS LP
By:	Global GP LLC, its general partner
By:	/s/Daphne H. Foster
	Title:  Chief Financial Officer

9

bank of america, n.a.,  as
Administrative Agent
By:	/s/Liliana Claar
Name:	Liliana Claar
Title:	Vice President

10

bank of america, n.a.,  as a Lender
By:	/s/Bryan Heller
Name:	Bryan Heller
Title:	Director

11

JPMORGAN CHASE BANK, N.A.,  as a Lender
By:	/s/Daniel J. Stampfel
Name:	Daniel J. Stampfel
Title:	Authorized Officer

12

CITIZENS BANK (F.K.A. rbs citizens NA),
as a Lender
By:	/s/Donald A. Wright
Name:	Donald A. Wright
Title:	SVP

13

wells fargo bank, n.a.,  as a Lender
By:	/s/Daniel M. Grondin
Name:	Daniel M. Grondin
Title:	Senior Vice President

14

societe generale,  as a Lender
By:	/s/Barbara Paulsen
Name:	Barbara Paulsen
Title:	MD

15

bnp paribas,  as a Lender
By:	/s/Pauline Blandin
Name:	Pauline Blandin
Title:	Associate
By:	/s/Jordan Nenoff
Name:	Jordan Nenoff
Title:	Director

16

COOPERATIEVE CENTRALE RAIFFEISEN-
BOERENLEENBANK B.A., “RABOBANK
NEDERLAND” NEW YORK BRANCH,  as a Lender
By:	/s/Chung-Taek Oh
Name:	Chung-Taek Oh
Title:	Executive Director
By:	/s/Gijs Vos
Name:	Gijs Vos
Title:	Managing Director

17

bmo harris financing, inc.,  as a Lender
By:	/s/Matthew L. Davis
Name:	Matthew L. Davis
Title:	Vice President

18

the bank of tokyo-mitsubishi ufj, ltd. NY BRANCH,  as a Lender
By:	/s/Andrew Oram
Name:	Andrew Oram
Title:	Managing Director

19

santander bank, n.a.,  as a Lender
By:	/s/William Maag
Name:	William Maag
Title:	Managing Director

20

credit agricole corporate and
investment bank,  as a Lender
By:	/s/Zali Win
Name:	Zali Win
Title:	Managing Director
By:	/s/William Purdy
Name:	William Purdy
Title:	Vice President

21

natixis, new york branch,  as a Lender
By:	/s/David Pershad
Name:	David Pershad
Title:	Managing Director
By:	/s/Alisa Trani
Name:	Alisa Trani
Title:	Director

22

sumitomo mitsui banking corporation, NY BRANCH,  as a Lender

By:

Name:

Title:

23

deutsche bank ag, new york branch,
as a Lender
By:	/s/Chris Chapman
Name:	Chris Chapman
Title:	Director
By:	/s/Shai Bandner
Name:	Shai Bandner
Title:	Vice President

24

td bank, n.a.,  as a Lender
By:	/s/Vijay Prasad
Name:	Vijay Prasad
Title:	Senior Vice President

25

keybank national association,  as a Lender
By:	/s/Keven D. Smith
Name:	Keven D. Smith
Title:	Senior Vice President

26

BARCLAYS BANK PLC,  as a Lender
By:	/s/Vanessa A. Kurbatskiy
Name:	Vanessa A. Kurbatskiy
Title:	Vice President

27

REGIONS BANK,  as a Lender
By:	/s/Richard Kaufman
Name:	Richard Kaufman
Title:	Senior Vice President

28

RAYMOND JAMES BANK, N.A.,  as a Lender
By:	/s/Scott G. Axelrod
Name:	Scott G. Axelrod
Title:	Senior Vice President

29

PEOPLE'S UNITED BANK, national
association, formerly PEOPLE'S UNITED
BANK,  as a Lender
By:	/s/Justin Mills
Name:	Justin Mills
Title:	Vice President

30

THE HUNTINGTON NATIONAL BANK,
as a Lender
By:	/s/Jared Shaner
Name:	Jared Shaner
Title:	Vice President

31

WEBSTER BANK, NATIONAL ASSOCIATION,
as a Lender
By:	/s/Raymond C. Hoefling
Name:	Raymond C. Hoefling
Title:	Senior Vice President

32

FIRST NIAGARA BANK, N.A.,  as a Lender
By:	/s/Robert Dellatorre
Name:	Robert Dellatorre
Title:	First Vice President

33

CADENCE BANK, N.A.,  as a Lender
By:	/s/Mike Ross
Name:	Mike Ross
Title:	Executive Vice President

34

RB INTERNATIONAL FINANCE (USA) LLC,
as a Lender
By:	/s/Astrid Wilke
Name:	Astrid Wilke
Title:	Group Vice President
By:	/s/Pearl Geffers
Name:	Pearl Geffers
Title:	First Vice President

35

BLUE HILLS BANK,  as a Lender
By:	/s/Kelley Keefe
Name:	Kelley Keefe
Title:	Senior Vice President

36

customers bank,  as a Lender
By:	/s/James B. Daley
Name:	James B. Daley
Title:	Vice President

37

RATIFICATION OF GUARANTY

Each of the undersigned guarantors (each a "Guarantor") hereby acknowledges and consents to the foregoing Fourth Amendment as of December18, 2015, and agrees that each of (a) the Second Amended and Restated Guaranty dated as of December 16, 2013 (as amended and in effect from time to time, the "OriginalGuaranty") from each of Global Partners LP and Bursaw Oil LLC; (b) the Guarantee dated as of September 8, 2014 (as amended and in effect from time to time, the "Canada Guaranty") from Global Partners Energy Canada ULC; and (c) the Guaranty dated as of January 7, 2015 (as amended and in effect from time to time, the "Warren Guaranty")from each of Warex Terminals Corporation, Drake Petroleum Company, Inc., Puritan Oil Company, Inc. and Maryland Oil Company, Inc. remains in full force and effect, and each of the Guarantors confirms and ratifies all of its obligations thereunder and under each of the other Loan Documents to which such Guarantor is a party. Notwithstanding anything to the contrary contained herein, the parties thereto hereby acknowledge, agree and confirm that as of the date hereof, each of the Original Guaranty, the Canada Guaranty and the Warren Guaranty remains in full force and effect.

GLOBAL PARTNERS LP
By:	Global GP LLC, its general partner
By:	/s/Daphne H. Foster
	Title: Chief Financial Officer
BURSAW OIL LLC
By:	Alliance Energy LLC, its sole member
By:	Global Operating LLC, its sole member
By:	Global Partners LP, its sole member
By:	Global GP LLC, its general partner
By:	/s/Daphne H. Foster
	Title: Chief Financial Officer
GLOBAL PARTNERS ENERGY CANADA ULC
By:	/s/Daphne H. Foster
	Title: Chief Financial Officer

38

WAREX TERMINALS CORPORATION
By:	/s/Daphne H. Foster
	Title: Chief Financial Officer
DRAKE PETROLEUM COMPANY, INC.
By:	/s/Daphne H. Foster
	Title: Chief Financial Officer
PURITAN OIL COMPANY, INC.
By:	/s/Daphne H. Foster
	Title: Chief Financial Officer
MARYLAND OIL COMPANY, INC.
By:	/s/Daphne H. Foster
	Title: Chief Financial Officer

39

EX-10.47

Exhibit 10.47

FIFTH AMENDMENT TO SECOND AMENDED AND RESTATED CREDIT AGREEMENT

This Fifth Amendment to Second Amended and Restated Credit Agreement(this "FifthAmendment") is made as of February 24, 2016, by and amongGLOBAL OPERATING LLC, a Delaware limited liability company ("OLLC"), GLOBAL COMPANIES LLC, a Delaware limited liability company ("Global"), GLOBAL MONTELLO GROUP CORP., a Delaware corporation ("Montello"), GLEN HES CORP., a Delaware corporation ("Glen Hes"), CHELSEA SANDWICH LLC, a Delaware limited liability company ("Chelsea LLC"), GLP FINANCE CORP., a Delaware corporation ("Finance"), GLOBAL ENERGY MARKETING LLC, a Delaware limited liability company ("GEM"), GLOBAL CNG LLC, a Delaware limited liability company ("CNG"), ALLIANCE ENERGY LLC, a Massachusetts limited liability company ("Alliance"),CASCADE KELLY HOLDINGS LLC, an Oregon limited liability company ("Cascade") and WARREN EQUITIES, INC., a Delaware corporation ("Warren" and, collectively with  OLLC, Global, Montello, Glen Hes, Chelsea LLC, Finance, GEM, CNG, Alliance and Cascade, the "Borrowers" and each individually, a"Borrower"), GLOBAL PARTNERS LP, a Delaware limited partnership (the "MLP"), each "Lender" (as such term is defined in the Credit Agreement referred to below) (collectively, the "Lenders" and each individually, a "Lender") party hereto, and Bank of America, N.A. as Administrative Agent (as such term is defined in the Credit Agreement), amending certain provisions of that certain Second Amended and Restated Credit Agreement dated as of December 16, 2013 (as amended and in effect from time to time, the "Credit Agreement") by and among the Borrowers, the MLP, the Lenders, the Administrative Agent, Swing Line Lender, the L/C Issuer, the Alternative Currency Fronting Lender, JPMorgan Chase Bank, N.A. and Wells Fargo Bank, N.A. as Co-Syndication Agents and Citizens Bank National Association (f/k/a RBS Citizens NA) and Societe Generale, as Co-Documentation Agents.  Capitalized terms used herein without definition and which are defined in the Credit Agreement shall have the same respective meanings herein as therein.

WHEREAS, the Loan Parties, the requisite Lenders andthe Administrative Agentdesire to amend certain provisions of the Credit Agreement, all as provided more fully herein below;

NOW, THEREFORE, in consideration of the premises and the mutual agreements contained herein and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto hereby agree as follows:

§1.    Amendment to Section 1 of the Credit Agreement.Section 1.01 of the Credit Agreement is hereby amended as follows:

(a)     the definition of "Applicable Revolver Rate" contained in Section 1.01 of the Credit Agreement is hereby amended by deleting such definition it its entirety and restating it as follows:

"Applicable Revolver Rate" means, in respect of the Revolver Loans and the commitment fees thereon, the applicable percentage per annum set forth below determined by reference to the Combined Total Leverage Ratio as set forth

in the most recent Compliance Certificate received by the Administrative Agent pursuant to Section 6.02(b):

Pricing Level	Combined Total Leverage Ratio	Applicable Revolver Rate for Base Rate Loans (in basis points)	Applicable Revolver Rate for Eurocurrency Rate Loans, Revolver Letters of Credit and Cost of Funds Rate Loans (in basis points)	Applicable Revolver Rate for commitment fees (in basis points)
1	Less than 2.00:1.00	125	225	37.5
2	Greater than or equal to 2.00:1.00 but less than 2.50:1.00	150	250	37.5
3	Greater than or equal to 2.50:1.00 but less than 3.00:1.00	175	275	37.5
4	Greater than or equal to 3.00:1.00 but less than 3.50:1.00	200	300	50.0
5	Greater than or equal to 3.50:1.00 but less than 4.50:1.00	225	325	50.00
6	Greater than or equal to 4.50:1.00	250	350	50.00

Any increase or decrease in the Applicable Revolver Rate resulting from a change in the Combined Total Leverage Ratio shall become effective as of the first Business Day immediately following the date a Compliance Certificate is delivered pursuant to Section 6.02(a);  provided,  however, that if a Compliance Certificate is not delivered when due in accordance with such Section, then, upon the request of the Required Lenders, the highest pricing level shall apply in respect of all the Revolver Loans and the commitment fees in respect thereof as of the first Business Day after the date on which such Compliance Certificate was required to have been delivered and in each case shall remain in effect until the date on which such Compliance Certificate is delivered.

Notwithstanding anything to the contrary contained in this definition, the determination of the Applicable Revolver Rate for any period shall be subject to the provisions of Section 2.09(b).

(b)      the definition of "Defaulting Lender" contained in Section 1.01 of the Credit Agreement is hereby amended by deleting the words "or (d) has, or has a direct or indirect parent company that has, (i) become the subject of a proceeding under any Debtor Relief Law, or (ii) had appointed for it a receiver, custodian, conservator, trustee, administrator, assignee for

2

the benefit of creditors or similar Person charged with reorganization or liquidation of its business or assets, including the Federal Deposit Insurance Corporation or any other state or federal regulatory authority acting in such a capacity" which appear in such definition and substituting in place thereof the words "or (d) has, or has a direct or indirect parent company that has, (i) become the subject of a proceeding under any Debtor Relief Law, (ii) had appointed for it a receiver, custodian, conservator, trustee, administrator, assignee for the benefit of creditors or similar Person charged with reorganization or liquidation of its business or assets, including the Federal Deposit Insurance Corporation or any other state or federal regulatory authority acting in such a capacity, or (iii) become the subject of a Bail-in Action".

(c)          by inserting the following definitions in the appropriate alphabetical order:

"Bail-In Action" means the exercise of any Write-Down and Conversion Powers by the applicable EEA Resolution Authority in respect of any liability of an EEA Financial Institution.

"Bail-In Legislation" means, with respect to any EEA Member Country implementing Article 55 of Directive 2014/59/EU of the European Parliament and of the Council of the European Union, the implementing law for such EEA Member Country from time to time which is described in the EU Bail-In Legislation Schedule.

"EEA Financial Institution" means (a) any credit institution or investment firm established in any EEA Member Country which is subject to the supervision of an EEA Resolution Authority, (b) any entity established in an EEA Member Country which is a parent of an institution described in clause (a) of this definition, or (c) any financial institution established in an EEA Member Country which is a subsidiary of an institution described in clauses (a) or (b) of this definition and is subject to consolidated supervision with its parent.

"EEA Member Country" means any of the member states of the European Union, Iceland, Liechtenstein, and Norway.

"EEA Resolution Authority" means any public administrative authority or any person entrusted with public administrative authority of any EEA Member Country (including any delegee) having responsibility for the resolution of any EEA Financial Institution.

"EU Bail-In Legislation Schedule" means the EU Bail-In Legislation Schedule published by the Loan Market Association (or any successor person), as in effect from time to time.

"Write-Down and Conversion Powers" means, with respect to any EEA Resolution Authority, the write-down and conversion powers of such EEA Resolution Authority from time to time under the Bail-In Legislation for the applicable EEA Member Country, which write-down and conversion powers are described in the EU Bail-In Legislation Schedule.

§2.      Amendment to Section 2.15 of the Credit Agreement.  Section 2.15(a)(iv) of the Credit Agreement is hereby amended by deleting the words "No reallocation hereunder shall

3

constitute a waiver or release" which appear in the last sentence of Section 2.15(a)(iv) and substituting in place thereof the words "Subject to Section 10.22, no reallocation hereunder shall constitute a waiver or release".

§3.Amendment to Article V of the Credit Agreement.  Article V of the Credit Agreement is hereby amended by inserting immediately after the text of Section 5.24 the following new Section 5.25:

5.25.   EEA Financial Institution.  No Loan Party is an EEA Financial Institution.

§4.      Amendment to Section 7.05 of the Credit Agreement.  Section 7.05(c) of the Credit Agreement is hereby amended by deleting the amount "$100,000,000" which appears in Section 7.05(c)(iii) and substituting in place thereof the amount "$150,000,000".

§5.      Amendment to Section 7.18 of the Credit Agreement.  Section 7.18(iv) of the Credit Agreement is hereby amended by deleting Section 7.18(iv) in its entirety and restating it as follows:

(iv)    Combined Total Leverage Ratio.  Permit the Combined Total Leverage Ratio as at the end of any fiscal quarter of the Borrowers to be greater than the applicable ratio set forth below opposite such fiscal quarter:

FiscalQuarterEnded	CombinedTotalLeverageRatio
December 31, 2015	4.50:1.00
March 31, 2016 - March 31, 2017	5.50:1.00
June 30, 2017 and each fiscal quarter ended thereafter	5.00:1.00

§6.         Amendment to Article X of the Credit Agreement.  Article X of the Credit Agreement is hereby amended by inserting immediately after the text of Section 10.21 the following new Section 10.22:

10.22. Acknowledgement and Consent to Bail-In of EEA Financial Institutions.  Notwithstanding anything to the contrary in any Loan Document or in any other agreement, arrangement or understanding among any such parties, each party hereto acknowledges that any liability of any Lender that is an EEA Financial Institution arising under any Loan Document, to the extent such liability is unsecured, may be subject to the write-down and conversion powers of an EEA Resolution Authority and agrees and consents to, and acknowledges and agrees to be bound by:

(a)     the application of any Write-Down and Conversion Powers by an EEA Resolution Authority to any such liabilities arising hereunder which may be payable to it by any Lender that is an EEA Financial Institution; and

(b)   the effects of any Bail-in Action on any such liability, including, if applicable:

4

(i)          a reduction in full or in part or cancellation of any such liability;

(ii)      a conversion of all, or a portion of, such liability into shares or other instruments of ownership in such EEA Financial Institution, its parent undertaking, or a bridge institution that may be issued to it or otherwise conferred on it, and that such shares or other instruments of ownership will be accepted by it in lieu of any rights with respect to any such liability under this Agreement or any other Loan Document; or

(iii)       the variation of the terms of such liability in connection with the exercise of the write-down and conversion powers of any EEA Resolution Authority.

§7.     Amendment to Schedule 2.01 of the Credit Agreement.  Schedule 2.01 of the Credit Agreement is hereby amended by deleting Schedule 2.01 in its entirety and replacing it with the Schedule 2.01 attached hereto.

§8.     Conditions to Effectiveness. This Fifth Amendment will become effective as of the date hereof upon receipt by the Administrative Agent of the following:

(a)       the fully executed counterparts of this Fifth Amendment (including the Ratification of Guaranty hereto) executed by the Loan Parties, the Administrative Agent and the required Lenders;

(b)     the fully executed original counterparts of a fee letter, executed by the Borrowers and the Administrative Agent; and

(c)       receipt by the Administrative Agent for the account of each Lender approving this Fifth Amendment and sending to the Administrative Agent its fully executed and delivered signature page hereto for receipt by the Administrative Agent by not later than 12:00 noon (Eastern time) on February 19, 2016, a fee in an amount of 12.5 basis points on the amount of such Lender's WC Commitment and Revolver Commitment as set forth on Schedule 2.01 attached hereto (which is after giving effect to the reduction in the such Lender's WC Commitment and Revolver Commitment contemplated by this Fifth Amendment).

§9.Representations and Warranties; No Default.  Each of the Loan Parties hereby repeats, on and as of the date hereof, each of the representations and warranties made by it in Article V of the Credit Agreement, provided, that all references therein to the Credit Agreement shall refer to such Credit Agreement as amended hereby.  In addition, each of the Loan Parties hereby represents and warrants that the execution and delivery by such Loan Party of this Fifth Amendment and the performance by each such Loan Party of all of its agreements and obligations under the Credit Agreement as amended hereby and the other Loan Documents to which it is a party are within the corporate, partnership and/or limited liability company authority of each of the Loan Parties and have been duly authorized by all necessary corporate, partnership and/or membership action on the part of each of the Loan Parties.  Each of the Loan Parties hereby certifies to the Administrative Agent and the Lenders that no Default or Event of Default has occurred and is continuing as of the date hereof.

5

§10.Ratification,  Etc.  Except as expressly amended hereby, the Credit Agreement and all documents, instruments and agreements related thereto, including, but not limited to the Security Documents, are hereby ratified and confirmed in all respects and shall continue in full force and effect.  The Credit Agreement and this Fifth Amendment shall be read and construed as a single agreement.  All references in the Credit Agreement or any related agreement or instrument to the Credit Agreement shall hereafter refer to the Credit Agreement as amended hereby.  This Fifth Amendment shall constitute a Loan Document.

§11.No Waiver.Nothing contained herein shall constitute a waiver of, impair or otherwise affect any Obligations, any other obligation of the Loan Parties or any rights of the Administrative Agent, the L/C Issuer, the Swing Line Lender, the Alternative Currency Fronting Lender, the Syndication Agent, the Co-Documentation Agents or the Lenders consequent thereon.

§12.Counterparts.  This Fifth Amendment may be executed in one or more counterparts, each of which shall be deemed an original but which together shall constitute one and the same instrument.Delivery of an executed counterpart of a signature page of this Agreement by facsimile or other electronic imaging means (e.g. "pdf" or "tif") shall be effective as delivery of a manually executed counterpart of this Agreement.

§13.Governing Law.THIS FIFTH AMENDMENT SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK.

6

IN WITNESS WHEREOF, the parties hereto have executed this Fifth Amendment as a document under seal as of the date first above written.

GLOBAL OPERATING LLC
By:	Global Partners LP, its sole member
By:	Global GP LLC, its general partner
By:	/s/ Daphne H. Foster
	Title: Chief Financial Officer
GLOBAL COMPANIES LLC
By:	Global Operating LLC, its sole member
By:	Global Partners LP, its sole member
By:	Global GP LLC, its general partner
By:	/s/ Daphne H. Foster
	Title: Chief Financial Officer
GLOBAL MONTELLO GROUP CORP.
By:	/s/ Daphne H. Foster
	Title:  Chief Financial Officer
CHELSEA SANDWICH LLC
By:	Global Operating LLC, its sole member
By:	Global Partners LP, its sole member
By:	Global GP LLC, its general partner
By:	/s/ Daphne H. Foster
	Title: Chief Financial Officer
GLEN HES CORP.
By:		/s/ Daphne H. Foster
	Title:  Chief Financial Officer

7

By
	GLP FINANCE CORP.
	By:	/s/ Daphne H. Foster
		Title: Chief Financial Officer
	GLOBAL ENERGY MARKETING LLC
	By:	Global Operating LLC, its sole member
	By:	Global Partners LP, its sole member
	By:	Global GP LLC, its general partner
	By:	/s/ Daphne H. Foster
		Title: Chief Financial Officer
	ALLIANCE ENERGY LLC
	By:	Global Operating LLC, its sole member
	By:	Global Partners LP, its sole member
	By:	Global GP LLC, its general partner
	By:	/s/ Daphne H. Foster
		Title:  Chief Financial Officer
	CASCADE KELLY HOLDINGS LLC
	By:	Global Operating LLC, its sole member
	By:	Global Partners LP, its sole member
	By:	Global GP LLC, its general partner
	By:	/s/ Daphne H. Foster
		Title: Chief Financial Officer
	GLOBAL CNG LLC
	By:	Global Operating LLC, its sole member
	By:	Global Partners LP, its sole member
	By:	Global GP LLC, its general partner
	By:	/s/ Daphne H. Foster
		Title: Chief Financial Officer

8

WARREN EQUITIES, INC.
By:	/s/ Daphne H. Foster
	Title: Chief Financial Officer
GLOBAL PARTNERS LP
By:	Global GP LLC, its general partner
By:	/s/ Daphne H. Foster
	Title: Chief Financial Officer

9

bank of america, n.a.,  as
Administrative Agent
By:	/s/Liliana Claar
Name:	Liliana Claar
Title:	Vice President

10

bank of america, n.a.,  as a Lender
By:	/s/Bryan Heller
Name:	Bryan Heller
Title:	Director

11

JPMORGAN CHASE BANK, N.A.,  as a Lender
By:	/s/Daniel J. Stampfel
Name:	Daniel J. Stampfel
Title:	Authorized Officer

12

ATI
	CITIZENS BANK NATIONAL ASSOCIATION,
	as a Lender
	By:	/s/Donald A. Wright
	Name:	Donald A. Wright
	Title:	Senior Vice President

13

wells fargo bank, n.a.,  as a Lender
By:	/s/Daniel M. Grondin
Name:	Daniel M. Grondin
Title:	Senior Vice President

14

societe generale,  as a Lender
By:	/s/Michiel Van der Voort
Name:	Michiel Van der Voort
Title:	Managing Director

15

bnp paribas,  as a Lender
By:	/s/Jordan Nenoff
Name:	Jordan Nenoff
Title:	Director
By:	/s/Pauline Blandin
Name:	Pauline Blandin
Title:	Associate

16

COOPERATIEVE RABOBANK U.A., NEW
YORK BRANCH,  as a Lender
By:	/s/Chung-Taek Oh
Name:	Chung-Taek Oh
Title:	Executive Director
By:	/s/Antonio Nanez
Name:	Antonio Nanez
Title:	Executive Director

17

bmo harris financing, inc.,  as a Lender
By:	/s/Matthew Davis
Name:	Matthew Davis
Title:	Vice President

18

the bank of tokyo-mitsubishi ufj, ltd.
NY BRANCH,  as a Lender
By:	/s/ Michel Kermarrec
Name:	Michel Kermarrec
Title:	Vice President

19

santander bank, n.a.,  as a Lender
By:	/s/William Maag
Name:	William Maag
Title:	Managing Director

20

credit agricole corporate and
investment bank,  as a Lender
By:	/s/ Mark Lvoff
Name:	Mark Lvoff
Title:	Managing Director
By:	/s/Zali Win
Name:	Zali Win
Title:	Managing Director

21

natixis, new york branch,  as a Lender
By:	/s/David Pershad
Name:	David Pershad
Title:	Managing Director
By:	/s/Alisa Trani
Name:	Alisa Trani
Title:	Director

22

sumitomo mitsui banking corporation, NY BRANCH,  as a Lender
By:	/s/ James D. Weinstein
Name:	James D. Weinstein
Title:	Managing Director

23

w
	deutsche bank ag, new york branch,
	as a Lender
	By:	/s/Chris Chapman
	Name:	Chris Chapman
	Title:	Director
	By:	/s/Shai Bandner
	Name:	Shai Bandner
	Title:	Vice President

24

td bank, n.a.,  as a Lender
By:	/s/Vijay Prasad
Name:	Vijay Prasad
Title:	Senior Vice President

25

keybank national association,  as a
Lender
By:	/s/Keven D. Smith
Name:	Keven D. Smith
Title:	Senior Vice President

26

BARCLAYS BANK PLC,  as a Lender
By:	/s/ Ronnie Glenn
Name:	Ronnie Glenn
Title:	Vice President

27

REGIONS BANK,  as a Lender
By:	/s/Richard Kaufman
Name:	Richard Kaufman
Title:	Managing Director

28

RAYMOND JAMES BANK, N.A.,  as a Lender
By:	/s/Scott G. Axelrod
Name:	Scott G. Axelrod
Title:	Senior Vice President

29

PEOPLE'S UNITED BANK, national
association, formerly PEOPLE'S UNITED
BANK,  as a Lender
By:	/s/ Jeffrey Giunta
Name:	Jeffrey Giunta
Title:	Vice President

30

THE HUNTINGTON NATIONAL BANK,
as a Lender
By:	/s/Jared Shaner
Name:	Jared Shaner
Title:	Vice President

31

WEBSTER BANK, NATIONAL ASSOCIATION,
as a Lender
By:	/s/Raymond C. Hoefling
Name:	Raymond C. Hoefling
Title:	Senior Vice President

32

FIRST NIAGARA BANK, N.A.,  as a Lender
By:	/s/Robert Dellatorre
Name:	Robert Dellatorre
Title:	Senior Vice President

33

CADENCE BANK, N.A.,  as a Lender
By:	/s/Mike Ross
Name:	Mike Ross
Title:	Executive Vice President

34

RB INTERNATIONAL FINANCE (USA) LLC,
as a Lender
By:	/s/Astrid Wilke
Name:	Astrid Wilke
Title:	Group Vice President
By:	/s/Pearl Geffers
Name:	Pearl Geffers
Title:	First Vice President

35

BLUE HILLS BANK,  as a Lender
By:	/s/Kelley Keefe
Name:	Kelley Keefe
Title:	Senior Vice President

36

customers bank,  as a Lender
By:	/s/James B. Daley
Name:	James B. Daley
Title:	Vice President

37

RATIFICATION OF GUARANTY

Each of the undersigned guarantors (each a "Guarantor") hereby acknowledges and consents to the foregoing Fifth Amendment as of February 24, 2016, and agrees that each of (a) the Second Amended and Restated Guaranty dated as of December 16, 2013 (as amended and in effect from time to time, the "OriginalGuaranty") from each of Global Partners LP and Bursaw Oil LLC; (b) the Guarantee dated as of September 8, 2014 (as amended and in effect from time to time, the "Canada Guaranty") from Global Partners Energy Canada ULC; and (c) the Guaranty dated as of January 7, 2015 (as amended and in effect from time to time, the "Warren Guaranty")from each of Warex Terminals Corporation, Drake Petroleum Company, Inc., Puritan Oil Company, Inc. and Maryland Oil Company, Inc. remains in full force and effect, and each of the Guarantors confirms and ratifies all of its obligations thereunder and under each of the other Loan Documents to which such Guarantor is a party. Notwithstanding anything to the contrary contained herein, the parties hereto hereby acknowledge, agree and confirm that as of the date hereof, each of the Original Guaranty, the Canada Guaranty and the Warren Guaranty remains in full force and effect.

GLOBAL PARTNERS LP
By:	Global GP LLC, its general partner
By:	/s/Daphne H. Foster
	Title:	Chief Financial Officer
BURSAW OIL LLC
By:	Alliance Energy LLC, its sole member
By:	Global Operating LLC, its sole member
By:	Global Partners LP, its sole member
By:	Global GP LLC, its general partner
By:	/s/ Daphne H. Foster
	Title:	Chief Financial Officer
GLOBAL PARTNERS ENERGY CANADA ULC
By:	/s/ Daphne H. Foster
	Title:	Chief Financial Officer

38

WAREX TERMINALS CORPORATION
By:	/s/ Daphne H. Foster
	Title:	Chief Financial Officer
DRAKE PETROLEUM COMPANY, INC.
By:	/s/ Daphne H. Foster
	Title:	Chief Financial Officer
PURITAN OIL COMPANY, INC.
By:	/s/ Daphne H. Foster
	Title:	Chief Financial Officer
MARYLAND OIL COMPANY, INC.
By:	/s/ Daphne H. Foster
	Title:	Chief Financial Officer

39

EX-21.1

Exhibit 21.1

LIST OF SUBSIDIARIES OF GLOBAL PARTNERS LP

Entity	Jurisdiction of Formation
Alliance Energy LLC	Massachusetts
Basin Transload, LLC	Delaware
Drake Petroleum Company, Inc.	Massachusetts
Global Companies LLC	Delaware
Global Montello Group Corp.	Delaware
Global Operating LLC	Delaware
GLP Finance Corp.	Delaware
Warex Terminals Corporation	Delaware
Warren Equities, Inc.	Delaware

EX-23.1

Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

We consent to the incorporation by reference in the following Registration Statements:

(1)	Registration Statements and related prospectus (Form S-3 Nos. 333-208138, 333-204233, 333-188982, 333-181211, 333-165789, 333-145144,  and 333-140525) of Global Partners LP
(2)	Registration Statements and related prospectus (Form S-4 Nos. 333-206851 and 333-202464 of Global Partners LP, and
(3)	Registration Statement (Form S-8 Nos. 333-182346 and 333-145579 ), pertaining to the Global Partners LP Long Term Incentive Plan;

of our reports dated February 29, 2016, with respect to the consolidated financial statements  and schedule of Global Partners LP and the effectiveness of internal control over financial reporting of Global Partners LP, included in this Annual Report (Form 10-K) of Global Partners LP for the year ended December 31, 2015.

	/s/ Ernst & Young LLP
Boston, Massachusetts February 29, 2016

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Eric Slifka, President and Chief Executive Officer of Global GP LLC, the general partner of Global Partners LP, certify that:

1.I have reviewed this annual report on Form 10‑K for the year ended December 31, 2015 of Global Partners LP;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a‑15(e) and 15d‑15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a‑15(f) and 15d‑15(f)) for the registrant and have:

a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Dated: February 29, 2016	By:	/s/ Eric Slifka
		Eric Slifka President and Chief Executive Officer of Global GP LLC, general partner of Global Partners LP

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Daphne H. Foster, Chief Financial Officer of Global GP LLC, the general partner of Global Partners LP, certify that:

1.I have reviewed this annual report on Form 10‑K for the year ended December 31, 2015 of Global Partners LP;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a‑15(e) and 15d‑15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a‑15(f) and 15d‑15(f)) for the registrant and have:

a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Dated: February 29, 2016	By:	/s/ Daphne H. Foster
		Daphne H. Foster Chief Financial Officer of Global GP LLC, general partner of Global Partners LP

EX-32.1

Exhibit 32.1

CERTIFICATION OF THE

CHIEF EXECUTIVE OFFICER OF

GLOBAL PARTNERS LP

PURSUANT TO 18 U.S.C. SECTION 1350

In connection with the accompanying report on Form 10‑K for the year ended December 31, 2015 of Global Partners LP (the “Partnership”) and filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Eric Slifka, President and Chief Executive Officer of Global GP LLC, the general partner of the Partnership, hereby certify, pursuant to Section 906 of the Sarbanes‑Oxley Act of 2002, that:

1.The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2.The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

Dated: February 29, 2016	By:	/s/ Eric Slifka
		Eric Slifka President and Chief Executive Officer of Global GP LLC, general partner of Global Partners LP

EX-32.2

Exhibit 32.2

CERTIFICATION OF THE

CHIEF FINANCIAL OFFICER OF

GLOBAL PARTNERS LP

PURSUANT TO 18 U.S.C. SECTION 1350

In connection with the accompanying report on Form 10‑K for the year ended December 31, 2015 of Global Partners LP (the “Partnership”) and filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Daphne H. Foster, Chief Financial Officer of Global GP LLC, the general partner of the Partnership, hereby certify, pursuant to Section 906 of the Sarbanes‑Oxley Act of 2002, that:

1.The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2.The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

Dated: February 29, 2016	By:	/s/ Daphne H. Foster
		Daphne H. Foster Chief Financial Officer of Global GP LLC, general partner of Global Partners LP

XML

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2015	Feb. 25, 2016	Jun. 30, 2015
Document and Entity Information
Entity Registrant Name	GLOBAL PARTNERS LP
Entity Central Index Key	0001323468
Document Type	10-K
Document Period End Date	Dec. 31, 2015
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$ 834,777,904
Entity Common Stock, Shares Outstanding		33,995,563
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	FY

XML

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$ 1,116	$ 5,238
Accounts receivable, net (less allowance of $5,942 and $4,818 as of December 31, 2015 and 2014, respectively)	311,354	457,730
Accounts receivable-affiliates	2,578	3,903
Inventories	388,952	336,813
Brokerage margin deposits	31,327	17,198
Derivate assets	66,099	83,826
Prepaid expenses and other current assets	65,609	54,315
Total current assets	867,035	959,023
Property and equipment, net	1,242,683	825,051
Intangible assets, net	75,694	48,902
Goodwill	435,369	154,078
Other assets	42,894	43,763
Total assets	2,663,675	2,030,817
Current liabilities:
Accounts payable	303,781	456,619
Working capital revolving credit facility-current portion	98,100
Line of credit		700
Environmental liabilities-current portion	5,350	3,101
Trustee taxes payable	95,264	105,744
Accrued expenses and other current liabilities	60,328	82,820
Derivative liabilities	31,911	58,507
Total current liabilities	594,734	707,491
Working capital revolving credit facility-less current portion	150,000	100,000
Revolving credit facility	269,000	133,800
Senior notes	656,564	360,096
Environmental liabilities-less current portion	67,883	34,462
Financing obligation	89,790
Deferred tax liabilities	84,836	12,958
Other long-term liabilities	56,884	45,854
Total liabilities	$ 1,969,691	$ 1,394,661
Commitments and contingencies (see Note 13)
Global Partners LP equity:
Common unitholders 33,995,563 units issued and 33,506,844 outstanding at December 31, 2015 and 30,995,563 units issued and 30,604,961 outstanding at December 31, 2014)	$ 657,071	$ 599,406
General partner interest (0.67% and 0.74% interest with 230,303 equivalent units outstanding at December 31, 2015 and 2014, respectively)	(1,188)	788
Accumulated other comprehensive loss	(8,094)	(13,252)
Total Global Partners LP equity	647,789	586,942
Noncontrolling interest	46,195	49,214
Total partners' equity	693,984	636,156
Total liabilities and partners' equity	$ 2,663,675	$ 2,030,817

XML

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
CONSOLIDATED BALANCE SHEETS
Common unitholders, units issued	33,995,563	30,995,563
Common unitholders, units outstanding	33,506,844	30,604,961
General partner interest (as a percent)	0.67%	0.74%
General partner interest, equivalent units outstanding	230,303	230,303
Accounts receivable, allowance (in dollars)	$ 5,942	$ 4,818

XML

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
CONSOLIDATED STATEMENTS OF OPERATIONS
Sales	$ 2,169,445	$ 2,486,203	$ 2,680,088	$ 2,979,116	$ 3,532,948	$ 4,050,458	$ 4,569,620	$ 5,116,928	$ 10,314,852	$ 17,269,954	$ 19,589,608
Cost of sales									9,717,183	16,725,167	19,185,052
Gross profit	132,624	152,299	144,188	168,558	142,643	155,435	87,685	159,024	597,669	544,787	404,556
Costs and operating expenses:
Selling, general and administrative expenses									177,043	153,961	115,491
Operating expenses									290,307	204,070	185,713
Amortization expense									13,499	18,867	19,216
Loss (gain) on sale and disposition of assets					(1,100)		(400)	(700)	2,097	2,182	(1,273)
Total costs and operating expenses									482,946	379,080	319,147
Operating income									114,723	165,707	85,409
Interest expense									(73,332)	(47,764)	(43,537)
Income before income tax expense									41,391	117,943	41,872
Income tax benefit (expense)									1,873	(963)	(819)
Net income	(2,905)	8,146	7,614	30,409	28,482	43,622	(12,278)	57,154	43,264	116,980	41,053
Net loss (income) attributable to noncontrolling interest									299	(2,271)	1,562
Net income attributable to Global Partners LP	(2,282)	8,212	7,218	30,415	27,910	42,508	(12,719)	57,010	43,563	114,709	42,615
Less: General partner's interest in net income, including incentive distribution rights									7,667	5,981	3,521
Limited partners’ interest in net income	$ (2,267)	$ 5,380	$ 4,547	$ 28,236	$ 26,093	$ 40,885	$ (13,752)	$ 55,502	$ 35,896	$ 108,728	$ 39,094
Basic net income per limited partner unit (in dollars per unit)	$ (0.70)	$ 0.16	$ 0.15	$ 0.92	$ 0.93	$ 1.50	$ (0.50)	$ 2.04	$ 1.12	$ 3.97	$ 1.43
Diluted net income per limited partner unit (in dollars per unit)	(0.70)	0.16	0.15	0.92	0.93	1.50	(0.50)	2.03	$ 1.11	$ 3.95	$ 1.42
Basic weighted average limited partner units outstanding (in units)									32,178	27,420	27,329
Diluted weighted average limited partner units outstanding (in units)									32,323	27,502	27,560
Distributions per limited partner unit (in dollars per unit)	$ 0.6975	$ 0.6925	$ 0.6800	$ 0.6650	$ 0.6525	$ 0.6375	$ 0.6250	$ 0.6125	$ 2.74	$ 2.53	$ 2.34

XML

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Net income	$ 43,264	$ 116,980	$ 41,053
Other comprehensive income (loss):
Change in fair value of cash flow hedges	4,047	3,151	3,930
Change in pension liability	1,111	(5,093)	4,430
Total other comprehensive income (loss) income	5,158	(1,942)	8,360
Comprehensive income	48,422	115,038	49,413
Comprehensive loss (income) attributable to noncontrolling interest	299	(2,271)	1,562
Comprehensive income attributable to Global Partners LP	$ 48,721	$ 112,767	$ 50,975

XML

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Cash flows from operating activities
Net income (loss)	$ 43,264	$ 116,980	$ 41,053
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	115,851	86,364	77,134
Amortization of deferred financing fees	5,899	5,627	6,897
Amortization of leasehold interests	794
Amortization of senior notes discount	1,089	559	368
Bad debt expense	1,172	1,700	4,145
Unit-based compensation expense	4,208	3,485	1,806
Write-off of financing fees		1,626
Loss (gain) on sale and disposition of assets	2,097	2,182	(1,273)
Deferred income taxes	(3,624)	(11)	336
Changes in operating assets and liabilities, excluding net assets acquired
Accounts receivable	154,716	226,962	8,524
Accounts receivable - affiliate	1,325	(2,499)	(97)
Inventories	(32,648)	235,993	61,992
Broker margin deposits	(14,129)	4,594	32,934
Prepaid expenses, all other current assets and other assets	12,526	(49,020)	11,226
Accounts payable	(172,318)	(324,500)	18,667
Trustee taxes payable	(15,648)	25,528	(11,278)
Change in derivatives	8,869	17,509	(5,778)
Accrued expenses, all other current liabilities and other long-term liabilities	(33,199)	26,841	(3,065)
Net cash provided by operating activities	62,506	344,902	255,147
Cash flows from investing activities
Acquisitions	(561,170)		(185,262)
Capital expenditures	(92,925)	(95,114)	(67,132)
Proceeds from sale of property and equipment	4,331	4,021	9,187
Net cash used in investing activities	(649,764)	(91,093)	(243,207)
Cash flows from financing activities
Proceeds from issuance of common units, net	109,305	137,844
Borrowings from (payments on) working capital revolving credit facility	148,100	(227,000)	(97,500)
Borrowings from (payments on) revolving credit facility	135,200	(300,900)	12,700
Proceeds from senior notes, net of discount	295,338	258,903	147,900
Repayment of senior notes		(40,244)
Proceeds from issuance of term loan			115,000
Repayment of term loan			(115,000)
(Payments on) borrowings from line of credit	(700)	(3,000)	3,700
Repurchase of common units	(3,892)	(8,632)	(4,590)
Repurchased Units Withheld for Tax Obligations			2,086
Noncontrolling interest capital contribution	2,560	8,200	1,425
Distribution to noncontrolling interest	(5,280)	(9,200)	(2,920)
Distributions to partners	(97,495)	(73,759)	(67,329)
Net cash provided by (used in) financing activities	583,136	(257,788)	(8,700)
Cash and cash equivalents
(Decrease) increase in cash and cash equivalents	(4,122)	(3,979)	3,240
Cash and cash equivalents at beginning of period	5,238	9,217	5,977
Cash and cash equivalents at end of period	1,116	5,238	9,217
Supplemental information
Cash paid during the period for interest	59,764	31,554	34,179
Cash paid during the period for income taxes	$ 2,772	757	$ 273
Non-cash exchange of 6.25% senior notes due 2022		$ 110,000

XML

CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical)	Dec. 31, 2014
CONSOLIDATED STATEMENTS OF CASH FLOWS
Stated interest rate (as a percent)	6.25%

XML

CONSOLIDATED STATEMENTS OF PARTNERS' EQUITY - USD ($) $ in Thousands	Common Units	General Partner Interest	Accumulated Other Comprehensive Loss	Noncontrolling Interest	Total
Balance at Dec. 31, 2012	$ 456,538	$ (407)	$ (19,670)		$ 436,461
Increase (Decrease) in Partners' Capital
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 (loss)			8,360		8,360
Unit-based compensation	1,806				1,806
Distributions to partners	(64,190)	(3,352)			(67,542)
Repurchase of common units	(4,590)				(4,590)
Dividends on repurchased units	213				213
Repurchased units withheld for tax obligation	(2,086)				(2,086)
Balance at Dec. 31, 2013	426,785	(238)	(11,310)	47,943	463,180
Increase (Decrease) in Partners' Capital
Issuance of common units	137,844				137,844
Net income (loss)	108,728	5,981		2,271	116,980
Noncontrolling interest capital contribution				8,200	8,200
Distribution to noncontrolling interest				(9,200)	(9,200)
Other comprehensive income (loss)			(1,942)		(1,942)
Unit-based compensation	3,485				3,485
Distributions to partners	(69,333)	(4,955)			(74,288)
Repurchase of common units	(8,632)				(8,632)
Dividends on repurchased units	529				529
Balance at Dec. 31, 2014	599,406	788	(13,252)	49,214	636,156
Increase (Decrease) in Partners' Capital
Issuance of common units	109,305				109,305
Net income (loss)	35,896	7,667		(299)	43,264
Noncontrolling interest capital contribution				2,560	2,560
Distribution to noncontrolling interest				(5,280)	(5,280)
Other comprehensive income (loss)					5,158
Unit-based compensation	4,208				4,208
Distributions to partners	(88,944)	(9,643)			(98,587)
Repurchase of common units	(3,892)				(3,892)
Dividends on repurchased units	1,092				1,092
Balance at Dec. 31, 2015	$ 657,071	$ (1,188)	$ (8,094)	$ 46,195	$ 693,984

XML

Organization and Basis of Presentation

12 Months Ended

Dec. 31, 2015

Organization and Basis of Presentation

Organization and Basis of Presentation

Note 1. Organization and Basis of Presentation

Organization

Global Partners LP (the “Partnership”) is a midstream logistics and marketing master limited partnership formed in March 2005 engaged in the purchasing, selling, storing and logistics of transporting petroleum and related products, including domestic and Canadian crude oil, gasoline and gasoline blendstocks (such as ethanol), distillates (such as home heating oil, diesel and kerosene), residual oil, renewable fuels, natural gas and propane. The Partnership also receives revenue from convenience store sales and gasoline station rental income. 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 owns transload and storage terminals in North Dakota and Oregon that extend its origin-to-destination capabilities from the mid-continent region of the United States and Canada to the East and West Coasts. The Partnership is one of the largest distributors of gasoline, distillates, residual oil and renewable fuels to wholesalers, retailers and commercial customers in the New England states and New York. As of December 31, 2015, the Partnership had a portfolio of 1,509 owned, leased and/or supplied gasoline stations, including 281 directly operated convenience stores, in the Northeast, Maryland and Virginia.

On January 7, 2015, the Partnership acquired, through one of its wholly owned subsidiaries, Global Montello Group Corp. (“GMG”), 100% of the equity interests in Warren Equities, Inc. (“Warren”) from The Warren Alpert Foundation. On January 14, 2015, the Partnership acquired the Revere terminal (the “Revere Terminal”) located in Boston Harbor in Revere, Massachusetts from Global Petroleum Corp. (“GPC”) and related entities. On June 1, 2015, the Partnership acquired, through one of its wholly owned subsidiaries, Alliance Energy LLC (“Alliance”), retail gasoline stations and dealer supply contracts from Capitol Petroleum Group (“Capitol”). See Note 3.

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 most of its gasoline station and convenience store employees and certain union personnel who are employed by GMG.

The General Partner, which holds a 0.67% general partner interest in the Partnership (reduced from 0.74% following the Partnership’s public offering of common units discussed in Note 15), is owned by affiliates of the Slifka family. As of December 31, 2015, affiliates of the General Partner, including its directors and executive officers and their affiliates, owned 7,434,775 common units, representing a 21.9% limited partner interest.

Ownership by affiliates of the General Partner decreased by approximately 4,305,522 common units (from 37.9% at December 31, 2014 to 21.9% at December 31, 2015), primarily as a result of the liquidation of AE Holdings Corp. (“AE Holdings”) in March 2015 and a subsequent intrafamily sale by the Estate of AlfredA. Slifka to a Slifka family member. Immediately prior to such liquidation, the directors and executive officers of the General Partner were deemed to beneficially own all 5,850,000 common units that were then owned by AE Holdings. Upon the liquidation of AE Holdings, the 5,850,000 common units were distributed to the stockholders of AE Holdings. An aggregate 1,956,234 common units were sold by certain of the stockholders of AE Holdings in a public offering in March 2015. As of December 31, 2015, approximately 2,306,960 common units of the 5,850,000 common units were held by certain of the directors and executive officers of the General Partner, and the remaining 1,586,806 common units were held by unaffiliated members of the Slifka family.

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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2015

Summary of Significant Accounting Policies

Summary of Significant Accounting Policies

Note 2. Summary of Significant Accounting Policies

Basis of Consolidation and Presentation

On January 7, 2015, the Partnership acquired 100% of the equity interests in Warren, on January 14, 2015, the Partnership acquired the Revere Terminal and on June 1, 2015, the Partnership acquired Capitol. The financial results of Warren and the Revere Terminal for the year ended December 31, 2015 and of Capitol for the seven months ended December 31, 2015 are included in the accompanying statement of operations for the year ended December 31, 2015.

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”). 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 operations for the year ended December 31, 2013.

See Note 3, “Business Combinations,” for additional information on the Partnership’s acquisitions. The accompanying consolidated financial statements as of December 31, 2015 and 2014 and for the years ended December 31, 2015, 2014 and 2013 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 statements 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 statements 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 sheets and statements of operations.

Reclassifications

Certain prior year amounts in the consolidated financial statements have been reclassified 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) fair value of derivative instruments, (iii) accruals and contingent liabilities, (iv) allowance for doubtful accounts, (v) Level 3 valuations for crude oil and propane forward purchase and sales contracts, and (vi) assumptions used to evaluate goodwill, property and equipment and intangibles for impairment and environmental and asset retirement obligations provisions and cost of sales accrual. Although the Partnership believes these estimates are reasonable, actual results could differ from these estimates.

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 results 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, 2015 and 2014, substantially all of the Partnership’s accounts receivable classified as current assets were within payment terms.

Inventories

The Partnership hedges substantially all of its petroleum and ethanol inventory using a variety of instruments, primarily exchange-traded futures contracts. These futures contracts are entered into when inventory is purchased and are either designated as fair value hedges against the inventory on a specific barrel basis for inventories qualifying for fair value hedge accounting or not designated and maintained as economic hedges against certain inventory of the Partnership on a specific barrel basis. Changes in fair value of these futures contracts, as well as the offsetting change in fair value on the hedged inventory, is recognized in earnings as an increase or decrease in cost of sales. All hedged inventory designated in a fair value hedge relationship is valued using the lower of cost, as determined by specific identification, or market, as determined at the product level. All petroleum and ethanol inventory not designated in a fair value hedging relationship is carried at the lower of historical cost, on a first-in, first-out basis, or market.

Convenience store inventory and Renewable Identification Numbers (“RINs”) inventory are carried at the lower of historical cost or market.

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

	2015		2014
Distillates: home heating oil, diesel and kerosene	$	156,411	$	163,679
Gasoline		62,467		82,080
Gasoline blendstocks		32,542		33,760
Crude oil		102,253		20,769
Residual oil		12,895		20,602
Propane and other		1,469		5,123
Renewable identification numbers (RINs)		803		2,057
Convenience store inventory		20,112		8,743
Total	$	388,952	$	336,813

In addition to its own inventory, the Partnership has exchange agreements for petroleum products and ethanol with unrelated third‑party suppliers, whereby it may draw inventory from these other suppliers (see Revenue Recognition) and suppliers may draw inventory from the Partnership. Positive exchange balances are accounted for as accounts receivable and amounted to $3.4 million and $3.9 million at December 31, 2015 and 2014, respectively. Negative exchange balances are accounted for as accounts payable and amounted to $12.1 million and $16.5 million at December 31, 2015 and 2014, 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 related to the Partnership’s terminal assets and gasoline stations is charged to cost of sales and all other depreciation is charged to selling, general and administrative expenses. Depreciation is charged 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:

Gasoline station buildings, improvements and storage tanks	15-25	years
Buildings, docks, terminal facilities and improvements	5-25	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.

No material impairment charges were required in 2015, 2014 and 2013. However, at December 31, 2015, the Partnership had a $39.4 million remaining net book value of long‑lived assets used at its crude oil transloading terminals in North Dakota. The long‑term recoverability of these assets might be adversely impacted by any prolonged decline in crude oil commodity prices or crude oil differentials. Over the long‑term, if these market conditions remain, this may become an indicator of the potential impairment of these North Dakota assets in the future. The Partnership will monitor the pricing environment and the related impact this may have on the North Dakota operating and cash flows and whether this would constitute an impairment indicator.

The Partnership evaluates its assets for impairment on a quarterly basis.

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. At December 31, 2015, goodwill recorded in the accompanying consolidated balance sheet aggregated $435.4 million, of which $121.7 million relates to the Wholesale segment and $313.7 million relates to the GDSO segment.

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 process of testing goodwill for impairment involves numerous judgments, assumptions and estimates made by management which inherently reflect a high degree of uncertainty. 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. In the quantitative assessment, the fair value of each reporting unit is determined and compared to the book value of the reporting unit. If the fair value of the reporting unit is less than the book value, including goodwill, then the recorded goodwill is impaired to its implied fair value with a charge to operations. The Partnership calculates the fair value of each reporting unit using a combination of discounted cash flows and market comparables.

Key assumptions included in the development of the discounted cash flow value for each reporting unit include:

Future commodity volumes and margins.  The discounted cash flows are based on a five-year forecast with an estimate of terminal value. In general, the reporting units’ fair values are most sensitive to volume and gross margin assumptions. In particular, the Wholesale segment’s cash flows are impacted by the crude oil market, given the Partnership’s 2013 investment in transloading terminals in North Dakota and Oregon. The significant decline in the price of crude oil and tight crude oil differentials negatively impacted the Partnership’s fiscal 2015 results. The Partnership expects low crude oil prices and tight differentials to continue for a period of time, which will negatively impact the Partnership’s 2016 performance with recovery expected in 2017. As a result of these market conditions, there is increased uncertainty and sensitivity relating to the Partnership’s future cash flow projections within its crude oil business on which the Wholesale reporting unit’s goodwill impairment analysis relies. If market conditions, and therefore the Partnership’s performance, are worse than its projections, the Partnership may record impairment charges in the future. Actual results may not be consistent with these judgments, assumptions and estimates, and goodwill impairment charges may be required in future periods. This could have an adverse impact on the Partnership’s financial position and results of operations.

Discount rate commensurate with the risks involved.  The Partnership applies a discount rate to its expected cash flows based on a variety of factors, including market and economic conditions, operational risk, regulatory risk and political risk. A higher discount rate decreases the net present value of cash flows.

Future capital requirements.  The Partnership’s estimates of future capital requirements are based upon a combination of authorized spending and internal forecasts.

On October 1, 2015, the Partnership completed its quantitative assessments for both the Wholesale and GDSO reporting units, and no impairment indicator was identified for either reporting unit. The declining crude oil prices, changes in certain market conditions, and decline in the Partnership’s common unit price, collectively caused the Partnership to reassess its goodwill for impairment as of December31, 2015 for the Wholesale reporting unit. Based on the results of this assessment, the Partnership concluded that step-two of the quantitative assessment was not necessary and no impairment was required. 

The fair values of the Partnership’s reporting units are based on underlying assumptions that represent the Partnership’s best estimates. Many of the factors used in assessing fair value are outside of the control of management. A further sustained decline in commodity prices may cause the Partnership to reassess its long-lived assets and goodwill for impairment, and could result in future non-cash impairment charges as a result of such impairment assessments. If the Partnership is required to perform step-two in the future for the Wholesale reporting unit, up to $121.7million of goodwill assigned to this reporting unit could be written off in the period of such impairment assessment.

During 2014, the Partnership completed step-one quantitative assessments for both the Wholesale and GDSO reporting units and no impairment was identified for either reporting unit. Due to declining oil prices and other market indicators at December 31, 2014, the Partnership updated the assessment of the recovery of goodwill through December 31, 2014 and concluded there was no impairment. During 2013, the Partnership completed a qualitative assessment for the GDSO reporting unit and no impairment was required. During 2013, a quantitative assessment was completed for the Wholesale reporting unit, and no impairment was required.

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.

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 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 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 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 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. The liability for an asset retirement obligation is recognized on a discounted basis in the year in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying cost of the asset. The Partnership had approximately $7.8 million and $3.8 million in total asset retirement obligations at December 31, 2015 and 2014, respectively, which are included in other long‑term liabilities in the accompanying balance sheets. Approximately $1.8 million and $0.9 million of these obligations at December 31, 2015 were assumed in the 2015 acquisitions of Warren and Capitol, respectively.

Leases

The Partnership had a throughput agreement with GPC with respect to its terminal in Revere, Massachusetts. This agreement was accounted for as an operating lease in 2014 and 2013. On January 14, 2015, the Partnership acquired the Revere terminal from GPC (see Note 3). The Partnership also has lease agreements with the Port of St. Helens for land and for access rights to a rail spur and dock located at its Oregon facility. The Partnership also has terminal and throughput lease arrangements with various unrelated oil terminals and third parties, certain of which arrangements have minimum usage requirements. In addition, the Partnership leases certain gasoline stations from third parties under long‑term arrangements with various expiration dates. The Partnership’s has a long‑term lease agreement with Getty Realty which enables the Partnership to supply and operate certain Getty Realty gasoline station sites.

The Partnership has future commitments, principally for office space and computer equipment, under the terms of operating lease arrangements. The Partnership also leases railcars and barges through various lease arrangements with various expiration dates. The Partnership has rental income from gasoline stations and cobranding arrangements and lease income from space leased to several unrelated third parties at several of our terminals. Additionally, the Partnership has capital leases for other computer equipment and leasehold improvements.

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

Product 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. The Partnership recognizes net exchange differentials due from exchange partners in sales upon delivery of product to an exchange partner.

The Partnership collects trustee taxes, which consist of various pass through taxes collected 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, crude oil and ethanol 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. 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 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.

On July 1, 2015 the Partnership commenced business in Canada through its wholly owned Canadian subsidiary, Global Partners Energy Canada,ULC (“GPEC”). GPEC predominantly consists of sourcing crude oil and other petroleum based products for sale to the Partnership and customers in Canada. GPEC is a taxable entity for Canadian corporate income and branch taxes. In its first year of operations, GPEC realized a pre-tax loss generating a net operating loss that might be used to offset future taxable income when GPEC operates at a profit. 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 the accounting guidance regarding income taxes. Based upon projections of future taxable income, limited capital assets and market conditions, the Partnership has provided a full valuation allowance against the GPEC deferred tax asset. See Note5.

Foreign Currency Transactions

Gains/(losses) realized from transactions denominated in foreign currencies are included in cost of sales in the consolidated statements of operations and totaled ($714,000),  ($25,000) and$162,000 for the years ended December 31, 2015, 2014 and 2013, respectively.

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 in investment‑grade securities. 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 and directly operated convenience stores are located in the Northeast, Maryland and Virginia.

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 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 that the Partnership distributes. Therefore, the Partnership’s volumes in gasoline 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 volumes are generally higher during the first and fourth quarters of the calendar year. These factors may result in fluctuations in the Partnership’s quarterly operating results.

The following table presents the Partnership’s product sales and other revenues as a percentage of the consolidated sales for the years ended December 31:

	2015		2014		2013
Gasoline sales: gasoline and gasoline blendstocks (such as ethanol)	59	%	60	%	58	%
Crude oil sales and crude oil logistics revenue	12	%	14	%	18	%
Distillates (home heating oil, diesel and kerosene), residual oil, natural gas and propane sales	25	%	25	%	23	%
Convenience store sales, rental income and sundry sales	4	%	1	%	1	%
Total	100	%	100	%	100	%

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

The Partnership principally uses derivative instruments, which include regulated exchange-traded futures and options contracts (collectively, “exchange-traded derivatives”) and physical and financial forwards and over-the counter (“OTC”) swaps (collectively, “OTC derivatives”), to reduce its exposure to unfavorable changes in commodity market prices and interest rates. The Partnership uses these exchange-traded and OTC derivatives to hedge commodity price risk associated with its inventory and undelivered forward commodity purchases and sales (“physical forward contracts”) and uses interest rate swap instruments to reduce its exposure to fluctuations in interest rates associated with the Partnership’s credit facilities. The Partnership accounts for derivative transactions in accordance with ASC 815, “Derivatives and Hedging,” and recognizes derivatives instruments as either assets or liabilities in the consolidated balance sheet and measures those instruments at fair value. The changes in fair value of the derivative transactions are presented currently in earnings, unless specific hedge accounting criteria are met.

The fair value of exchange-traded derivative transactions reflects amounts that would be received from or paid to the Partnership’s brokers upon liquidation of these contracts. The fair value of these exchange-traded derivative transactions are presented on a net basis, offset by the cash balances on deposit with the Partnership’s brokers, presented as brokerage margin deposits in the consolidated balance sheets. The fair value of OTC derivative transactions reflects amounts that would be received from or paid to a third party upon liquidation of these contracts under current market conditions. The fair value of these OTC derivative transactions is presented on a gross basis as derivative assets or derivative liabilities in the consolidated balance sheets, unless a legal right of offset exists. The presentation of the change in fair value of the Partnership’s exchange-traded derivatives and OTC derivative transactions depends on the intended use of the derivative and the resulting designation.

Derivatives Accounted for as Hedges – The Partnership utilizes fair value hedges and cash flow hedges to hedge commodity price risk and interest rate risk.

Fair Value Hedges

Derivatives designated as fair value hedges are used to hedge price risk in commodity inventories and principally include exchange-traded futures contracts that are entered into in the ordinary course of business. For a derivative instrument designated as a fair value hedge, the gain or loss is recognized in earnings in the period of change together with the offsetting change in fair value on the hedged item of the risk being hedged. Gains and losses related to fair value hedges are recognized in the consolidated statement of operations through cost of sales. These futures contracts are settled on a daily basis by the Partnership through brokerage margin accounts.

Cash Flow Hedges

Derivatives designated as cash flow hedges are used to hedge interest rate risk from fluctuations in interest rates and may include various interest rate derivative instruments entered into with major financial institutions. For a derivative instrument being designated as a cash flow hedge, the effective portion of the derivative gain or loss is initially reported as a component of other comprehensive income (loss) and subsequently reclassified into the consolidated statement of operations through interest expense in the same period that the hedged exposure affects earnings. The ineffective portion is recognized in the consolidated statement of operations immediately.

Derivatives Not Accounted for as Hedges – The Partnership utilizes petroleum and ethanol commodity contracts, natural gas commodity contracts and foreign currency derivatives to hedge price and currency risk in certain commodity inventories and physical forward contracts.

Petroleum and Ethanol Commodity Contracts

The Partnership uses exchange-traded derivative contracts to hedge price risk in certain commodity inventories which do not qualify for fair value hedge accounting or are not designated by the Partnership as fair value hedges. Additionally, the Partnership uses exchange-traded derivative contracts, and occasionally financial forward and OTC swap agreements, to hedge commodity price exposure associated with its physical forward contracts which are not designated by the Partnership as cash flow hedges. These physical forward contracts, to the extent they meet the definition of a derivative, are considered OTC physical forwards and are reflected as derivative assets or derivative liabilities in the consolidated balance sheet. The related exchange-traded derivative contracts (and financial forward and OTC swaps, if applicable) are also reflected as brokerage margin deposits (and derivative assets or derivative liabilities, if applicable) in the consolidated balance sheet, thereby creating an economic hedge. Changes in fair value of these derivative instruments are recognized in the consolidated statement of operations through cost of sales. These exchange-traded derivatives 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 commodity product purchase and sale activities, it may experience net unbalanced positions for short periods of time as a result of variances in daily purchases and 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, the Partnership is aided by maintaining a constant presence in the marketplace. The Partnership also engages in a controlled trading program for up to an aggregate of 250,000 barrels of commodity products at any one point in time. Changes in fair value of these derivative instruments are recognized in the consolidated statement of operations through cost of sales.

Natural Gas Commodity Contracts

The Partnership uses physical forward purchase contracts to hedge price risk associated with the marketing and selling of natural gas to third-party users. These physical forward purchase commitments for natural gas are typically executed when the Partnership enters into physical forward sale commitments of product for physical delivery. These physical forward contracts, to the extent they meet the definition of a derivative, are reflected as derivative assets and derivative liabilities in the consolidated balance sheet. Changes in fair value of the forward purchase and sale commitments are recognized in the consolidated statement of operations through cost of sales.

Foreign Currency Contracts

The Partnership uses forward foreign currency contracts to hedge certain foreign denominated (Canadian) commodity product purchases. These forward foreign currency contracts are not designated by the Partnership as hedges and are reflected as prepaid expenses and other current assets or accrued expenses and other current liabilities in the consolidated balance sheets. Changes in fair values of these forward foreign currency contracts are reflected in cost of sales.

Margin Deposits

All of the Partnership’s exchange-traded derivative contracts (designated and not designated) are transacted through clearing brokers. The Partnership deposits initial margin with the clearing brokers, along with variation margin, which is paid or received on a daily basis, based upon the changes in fair value of open futures contracts and settlement of closed futures contracts. Cash balances on deposit with clearing brokers and open equity are presented on a net basis within brokerage margin deposits in the consolidated balance sheets.

Please See Note 4 “Derivative Financial Instruments,” for additional information.

Fair Value Measurements

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Partnership utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. The Partnership primarily applies the market approach for recurring fair value measurements and endeavors to utilize the best available information. Accordingly, the Partnership utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The Partnership is able to classify fair value balances based on the observability of those inputs. The fair value hierarchy that prioritizes the inputs used to measure fair value, giving the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). At each balance sheet reporting date, the Partnership categorizes its financial assets and liabilities using the three levels of the fair value hierarchy defined as follows:

Level 1—Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as the Partnership’s exchange-traded derivative instruments and pension plan assets.

Level 2—Quoted prices in active markets are not available; however, pricing inputs are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Level 2 primarily consists of non-exchange-traded derivatives such as OTC derivatives.

Level 3—Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. Level 3 includes certain OTC forward derivative instruments related to crude oil and propane.

Please see Note18, “Fair Value Measurements,” for additional information.

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 unitholders, or limited partners’ interest, and to the General Partner’s general partner interest.

Common units outstanding as reported in the accompanying consolidated financial statements at December31, 2015 and 2014 excluded  403,922 and 390,602common 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, 2015
			Limited		General
			Partner		Partner
Numerator:	Total		Interest		Interest		IDRs
Net income attributable to Global Partners LP (1)	$	43,563	$	35,896	$	7,667	$	—
Declared distribution	$	92,059	$	84,055	$	582	$	7,422
Assumed allocation of undistributed net income		(48,496)		(48,159)		(337)		—
Assumed allocation of net income	$	43,563	$	35,896	$	245	$	7,422
Denominator:
Basic weighted average limited partner units outstanding				32,178
Dilutive effect of phantom units				145
Diluted weighted average limited partner units outstanding				32,323
Basic net income per limited partner unit			$	1.12
Diluted net income per limited partner unit			$	1.11

	Year Ended December 31, 2014
			Limited		General
			Partner		Partner
Numerator:	Total		Interest		Interest		IDRs
Net income attributable to Global Partners LP (2)	$	114,709	$	108,728	$	5,981	$	—
Declared distribution	$	78,771	$	73,143	$	593	$	5,035
Assumed allocation of undistributed net income		35,938		35,585		353		—
Assumed allocation of net income	$	114,709	$	108,728	$	946	$	5,035
Denominator:
Basic weighted average limited partner units outstanding				27,420
Dilutive effect of phantom units				82
Diluted weighted average limited partner units outstanding				27,502
Basic net income per limited partner unit			$	3.97
Diluted net income per limited partner unit			$	3.95

(1) As a result of the June 2015 issuance of 3,000,000 common units (see Note15), the general partner interest was reduced to 0.67% from 0.74% and was, based on a weighted average, approximately 0.70%for the year ended December31, 2015.

(2) As a result of the December 2014 issuance of 3,565,000 common units (see Note15), the general partner interest was reduced to 0.74% from 0.83%. The issuance of these common units did not have a material impact on the Partnership’s basic or diluted net income per limited partner unit for the year ended December31, 2014.

	Year Ended December 31, 2013
			Limited		General
			Partner		Partner
Numerator:	Total		Interest		Interest		IDRs
Net income attributable to Global Partners LP	$	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

The board of directors of the General Partner declared the following quarterly cash distributions for the four quarters ended December 31, 2015:

	Per Unit Cash			Distribution Declared for the
Cash Distribution Declaration Date	Distribution Declared			Quarterly Period Ended
April 22, 2015	$	0.6800	(1)	March 31, 2015
July 22, 2015	$	0.6925	(1)	June 30, 2015
October 21, 2015	$	0.6975	(1)	September 30, 2015
January 28, 2016	$	0.4625		December 31, 2015

(1) This declared cash distribution resulted in an incentive distribution to the General Partner, as the holder of the IDRs, and enable the Partnership to exceed its third 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 November 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2015-17, “Income Taxes: Balance Sheet Classification of Deferred Taxes.” This standard simplifies the presentation of deferred income taxes and provides presentation requirements to classify deferred tax assets and liabilities as non-current in a classified statement of financial position. The standard is effective for fiscal years beginning after December5, 2016, including interim periods within those fiscal years. The Partnership early adopted this standard as of December31, 2015 and applied the guidance retrospectively. As a result, as of December31, 2014, current deferred taxes included in prepaid expenses and other current assets decreased by $1.1million and long-term deferred income taxes increased by $1.1million. The adoption of this standard did not have a material impact on the Partnership’s consolidated financial statements. See Note 5.

In April 2015, the FASB issued ASU No. 2015-03, “Interest-Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs.” This standard requires debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying value of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by this standard. The amendments in this standard are effective retrospectively for fiscal years, and interim periods within those years, beginning after December 15, 2015. The Partnership adopted this standard as of December31, 2015 and, as a result, reclassed unamortized debt issuance costs of approximately $6.9 million from other assets and $1.1 million from prepaid expenses and other current assets, a total of $8.0 million, to a reduction of senior notes in the accompanying balance sheet as of December31, 2014. The adoption of this standard did not have a material impact on the Partnership’s consolidated financial statements. See Note 8.

Accounting Standards or Updates Not Yet Effective

In February 2016, the FASB issued ASU No. 2016-02, “Leases.” This standard amends the existing accounting standards for lease accounting, including requiring lessees to recognize most leases on their balance sheets and making targeted changes to lessor accounting. This standard is effective beginning in the first quarter of 2019. Early adoption of this standard is permitted. The standard requires a modified retrospective transition approach for all leases existing at, or entered into after, the date of initial application, with an option to use certain transition relief. The Partnership is assessing the impact this standard will have on its consolidated financial statements.

In January 2016, the FASB issued ASU No. 2016-01, “Financial Instruments - Recognition and Measurement of Financial Assets and Financial Liabilities”. This standard revises the classification and measurement of investments in certain equity investments and the presentation of certain fair value changes for certain financial liabilities measured at fair value. This standard also requires the change in fair value of many equity investments to be recognized in net income. This standard is effective for interim and annual periods beginning after December 15, 2017, with early adoption permitted. The adoption of this standard is not expected to have a material impact on the Partnership’s consolidated financial statements.

In September 2015, the FASB issued ASU No. 2015-16, “Business Combinations: Simplifying the Accounting for Measurement-Period Adjustments.” This standard eliminates the requirement that an acquirer in a business combination account for measurement-period adjustments retrospectively. Instead, acquirers must recognize measurement-period adjustments during the period in which they determine the amounts, including the effect on earnings of any amounts they would have recorded in previous periods if the accounting had been completed at the acquisition date. The acquirer still must disclose the amounts and reasons for adjustments to the provisional amounts. The acquirer also must disclose, by line item, the amount of the adjustment reflected in the current-period income statement that would have been recognized in previous periods if the adjustment to provisional amounts had been recognized as of the acquisition date. Alternatively, an acquirer may present those amounts separately on the face of the income statement. This new standard is effective for fiscal years beginning after December 15, 2015, including interim periods within those fiscal years. Early adoption is permitted. The adoption of this standard is not expected to have a material impact on the Partnership’s consolidated financial statements.

In July 2015, the FASB issued ASU No. 2015-11, “Simplifying the Measurement of Inventory,” which requires an entity to measure inventory within the scope of the amendment at the lower of cost and net realizable value. Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. The new standard is effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years. The Partnership is assessing the impact this standard will have on its consolidated financial statements.

In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers,” that introduces a new five-step revenue recognition model in which an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This standard also requires disclosures sufficient to enable users to understand the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers, including qualitative and quantitative disclosures about contracts with customers, significant judgments and changes in judgments, and assets recognized from the costs to obtain or fulfill a contract. In July 2015, the FASB approved a one-year deferral of the effective date of the standard to fiscal periods beginning after December 15, 2017. The Partnership is evaluating the new guidance to determine the impact it will have on its consolidated financial statements.

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Business Combinations

12 Months Ended

Dec. 31, 2015

Business Combinations

Business Combinations

Note 3. Business Combinations

2015 Acquisitions

Warren Equities, Inc.—On January7, 2015, the Partnership acquired, through GMG, 100% of the equity interests in Warren, one of the largest independent marketers of petroleum products in the Northeast, from The Warren Alpert Foundation. The acquisition included 147 company-owned Xtra Mart convenience stores and related fuel operations, 53 commission agent locations and fuel supply rights for approximately 330 dealers. The acquired properties are located in the Northeast, Maryland and Virginia. The purchase price, inclusive of post-closing adjustments, was approximately $381.8 million, including working capital. The acquisition was funded with borrowings under the Partnership’s credit facility and with proceeds from its December 2014 public offering of 3,565,000 common units.

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 Warren subsequent to the acquisition date.

The following table presents the final 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	$	9,511
Inventory		19,144
Prepaid expenses and other current assets		11,038
Property and equipment		255,148
Intangibles		38,360
Other non-current assets		16,595
Total identifiable assets purchased		349,796
Liabilities assumed:
Accounts payable		(23,067)
Environmental liabilities		(36,467)
Taxes payable		(5,168)
Accrued expenses		(4,462)
Long-term deferred taxes		(75,501)
Other non-current liabilities		(9,739)
Total liabilities assumed		(154,404)
Net identifiable assets acquired		195,392
Goodwill		186,437
Net assets acquired	$	381,829

The fair value of loan receivables purchased of $25.0 million was estimated by management based on the receivable’s payment terms, assumptions of current interest rates and collectability and is included in prepaid expenses and other current assets and other non-current assets. The gross contractual amount for these loan receivables is $29.1 million, of which the Partnership estimates $2.4 million is not collectible.

The liability for environmental matters has been estimated by the Partnership with the assistance from third-party environmental engineers (see Note 9). Based on an analysis, the estimated provision for environmental matters related to Warren is $36.5 million.

The long-term deferred tax liabilities of $75.5 million is primarily related to temporary differences associated with the fair value allocations of property and equipment and intangible assets, which are not deductible for tax purposes, net of acquired environmental liabilities and other deductible accrued liabilities.

The Partnership engaged a third-party valuation firm to assist in the valuation of Warren’s property and equipment, intangible assets consisting of supply contracts and favorable leasehold interests, and unfavorable leasehold interests. The Partnership’s third-party valuation firm considered the income, market, and cost approaches in estimating the fair value of the property and equipment, supply contracts and leasehold interests. The income, market, and cost approaches were used to value the property and equipment based on the underlying asset class components of the property and equipment. The excess earnings method under the income approach was used to value the supply contracts. The income approach was used to value the favorable and unfavorable leasehold interests.

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 Gasoline Distribution and Station Operations (“GDSO”) reporting unit. The goodwill recognized is attributable primarily to expected synergies and growth opportunities for the Partnership. For federal income tax purposes, the acquisition of Warren was deemed to be a stock purchase and, therefore, any recorded goodwill is not expected to be tax deductible. In accordance with the stock purchase agreement between the Partnership and Warren, the Partnership is ultimately not responsible for federal income tax obligations for the interim period, June 1, 2014 to January 6, 2015 (Warren’s fiscal year end was May 31). Any tax obligations will be funded by the selling shareholders. Any tax refund will be remitted to the selling shareholders. Included in accounts receivable and accounts payable at December 31, 2015 is an estimated refund of $8.3 million to be paid to the selling shareholder of Warren. In addition, reflected in accounts payable is a $1.8 million payable representing planned utilization of net operating losses, the benefit of which was an assumed liability of the Partnership.

The fair values of the remaining Warren assets and liabilities noted above approximate their carrying values at January 7, 2015.

As part of the purchase price allocation, identifiable intangible assets include $37.6 million of supply contracts and $0.8 million of favorable leasehold interests that are being amortized over seven to ten years and five years, respectively. The weighted average life over which these acquired intangibles are being amortized is approximately ten and five years, respectively. The supply contracts are subject to renewals, and assumptions related to the renewals have been included in the determination of the value of the supply contracts at the date of acquisition. The Partnership determines the renewal assumptions used based on management’s assumptions of future events, including customer demand, customer attrition rates, contract renewal length and market overall conditions. The supply contracts had a weighted average term of approximately five years prior to their next renewal. Amortization expense related to the supply contracts amounted to $3.9 million for the year ended December 31, 2015.

The estimated remaining amortization expense for the supply contracts acquired in connection with the acquisition for each of the five succeeding years and thereafter is as follows (in thousands):

2016	$	3,899
2017		3,899
2018		3,899
2019		3,899
2020		3,899
Thereafter		13,931
Total	$	33,426

Amortization related to the favorable leasehold interests was immaterialfor the year ended December 31, 2015. The estimated remaining amortization for favorable leasehold interests acquired in connection with the acquisition for each of the four succeeding years is as follows (in thousands):

2016	$	152
2017		152
2018		152
2019		152
Total	$	608

In connection with the acquisition of Warren, the Partnership incurred acquisition costs of $5.4 million and $1.7 million for the years ended December 31, 2015 and 2014, respectively, which are included in selling, general and administrative expenses in the accompanying consolidated statements of operations. Additionally, in January 2015 and subsequent to the acquisition date, the Partnership recorded a restructuring charge of approximately $2.3 million, which is included in selling, general and administrative expenses in the accompanying consolidated statement of operations for the year ended December 31, 2015. This charge, which was principally for redundant and/or eliminated positions as a result of the acquisition, was not part of the purchase price allocation. The $2.3 million restructuring charge was paid during the year ended December 31, 2015.

The acquisition of Warren complements the Partnership’s existing retail presence in the Northeast and expands its footprint into the adjacent Mid-Atlantic region. The Warren operations have been integrated into the Partnership’s GDSO reporting segment.

Revere Terminal—On January 14, 2015, through the Partnership’s wholly owned subsidiary, Global Companies, the Partnership acquired the Revere Terminal located in Boston Harbor in Revere, Massachusetts from GPC, a privately held affiliate of the Partnership, and related entities for a purchase price of $23.7 million. The acquisition includes contingent consideration which would be payable under specific circumstances involving a subsequent sale of the property during the next eight years. The contingent consideration was estimated to be $0 as of the acquisition date and as of December 31, 2015 as the Partnership concluded that the treatment of the contingent consideration as a non-fair value measure is appropriate and that, as of December 31, 2015, the sale of the terminal for non-petroleum use within the next eight years is not probable. The Partnership financed the transaction with borrowings under its revolving credit facility. In connection with the Revere Terminal transaction, the pre-existing terminal storage rental and throughput agreement between the Partnership and GPC was terminated.

The acquisition was accounted for using the purchase method of accounting in accordance with the FASB’s guidance regarding business combinations. As the acquisition transitioned the Revere Terminal from a formerly leased facility to an owned facility, the transaction did not have a material impact on the Partnership’s consolidated financial statements.

The following table presents the final 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:
Property and equipment	$	28,481
Total identifiable assets purchased		28,481
Liabilities assumed:
Environmental liabilities		(3,074)
Other non-current liabilities		(1,757)
Total liabilities assumed		(4,831)
Net assets acquired	$	23,650

The liability for environmental matters has been estimated by the Partnership with the assistance from third-party environmental engineers (see Note 9). Based on an analysis, the estimated provision for environmental matters related to the Revere Terminal is $3.1 million.

The Partnership engaged a third-party valuation firm to assist in the valuation of the Revere Terminal’s property and equipment. The Partnership’s third-party valuation firm considered the income, market and cost approaches in estimating the fair value of the property and equipment. The market and cost approaches were principally used to value the property and equipment based on the underlying asset class components of the property and equipment. The fair values of the remaining Revere Terminal liabilities noted above approximate their carrying values at January14, 2015.

Capitol Petroleum Group—On June 1, 2015, the Partnership acquired 97 primarily Mobil and Exxon branded owned or leased retail gasoline stations and seven dealer supply contracts in New York City and Prince George’s County, Maryland, along with certain related supply and franchise agreements and third-party leases and other assets associated with the operations from Liberty Petroleum Realty,LLC, East River Petroleum Realty,LLC, Big Apple Petroleum Realty,LLC, White Oak Petroleum,LLC, Anacostia Realty,LLC, Mount Vernon Petroleum Realty,LLC and DAG Realty,LLC (collectively, “Capitol Petroleum Group”). The purchase price was approximately $155.7 million. The acquisition was financed with borrowings under the Partnership’s revolving 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 Capitol subsequent to the acquisition date.

The following table presents the final 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:
Inventory	$	346
Property and equipment		149,583
Intangibles		3,000
Other non-current assets		57
Total identifiable assets purchased		152,986
Liabilities assumed:
Financing obligation		(89,613)
Environmental liabilities		(300)
Other non-current liabilities		(2,236)
Total liabilities assumed		(92,149)
Net identifiable assets acquired		60,837
Goodwill		94,854
Net assets acquired	$	155,691

The liability for environmental matters was developed by management based on their estimates, assumptions and acquisition history (see Note 9). Based on an analysis, the estimated provision for environmental matters related to Capitol is $0.3 million.

The Partnership engaged a third-party valuation firm to assist in the valuation of Capitol’s property and equipment, intangible assets consisting of supply contracts and favorable leasehold interests and unfavorable leasehold interests. The Partnership’s third-party valuation firm considered the income, market and cost approaches in estimating the fair value of the property and equipment, supply contracts and leasehold interests. The market and cost approaches were used to value the property and equipment based on the underlying asset class components of the property and equipment. The excess earnings method under the income approach was used to value the supply contracts. The income approach was used to value the favorable and unfavorable leasehold interests.

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 GDSO reporting unit. The goodwill recognized is attributable primarily to the expansion of the Partnership’s presence in active markets in the East Coast in which the Partnership can leverage its existing operations and dealer relationships without significant incremental expense to grow the business. The transaction also positions the Partnership to expand through tuck-in acquisitions as well as new-to-industry sites. The goodwill is tax deductible. The operations of Capitol have been integrated into the Partnership’s GDSO reporting segment.

The estimated fair value of property and equipment of $149.6 million includes $60.0 million of owned property and equipment and $89.6 million of certain properties previously sold by Capitol within two sale-leaseback transactions that did not meet the criteria for sale accounting. As a result of not meeting the criteria for sale accounting, the property and equipment sold and leased back by Capitol has not been derecognized and, in purchase accounting, the estimated fair value of property and equipment associated with these sites has been recognized within property and equipment. Depreciation expense associated with these sale-leaseback properties amounted to $2.1 million for the year ended December 31, 2015.

The financing obligation of $89.6 million recognized is attributable to the two sale-leaseback transactions discussed above that did not meet the criteria for sale accounting and, as a result, were accounted for as financing arrangements. These lease agreements mature in May 2028 and September 2029, and the fair value assigned to the financing obligation was estimated by management based on the remaining payments attributable to the lease agreements over their terms and is equal to the estimated fair value of property and equipment associated with these sites. Over the course of the lease agreements, the lease rental payments will be classified as interest expense on the financing obligation and the pay-down of the financing obligation as opposed to operating expense. Interest expense and lease rental payments associated with the financing obligation for these sale-leaseback properties amounted to $5.6 million and $5.4 million for the year ended December 31, 2015, respectively. The financing obligation balance outstanding at December 31, 2015 was $89.8 million.

The fair values of the remaining Capitol assets and liabilities noted above approximate their carrying values at June1, 2015.

As part of the purchase price allocation, identifiable intangible assets include $0.8million of supply contracts and $2.2million of favorable leasehold interests that are being amortized over seven and two years, respectively. The weighted average life over which these acquired intangibles are being amortized is approximately seven and two years, respectively. The supply contracts are subject to renewals, and assumptions related to the renewals have been included in the determination of the value of the supply contracts at the date of acquisition. The Partnership determines the renewal assumptions used based on management’s assumptions of future events, including customer demand, customer attrition rates, contract renewal length and market overall conditions. The supply contracts had a weighted average term of approximately one year prior to their next renewal. Amortization expense related to the supply contracts was immaterial for the year ended December 31, 2015.

The estimated remaining amortization expense for the supply contracts acquired in connection with the acquisition for each of the five succeeding years and thereafter is as follows (in thousands):

2016	$	114
2017		114
2018		114
2019		114
2020		114
Thereafter		163
Total	$	733

Amortization of favorable leasehold interests was $0.6 million for the year ended December31, 2015. The estimated remaining amortization for favorable leasehold interests acquired in connection with the acquisition for each of the two succeeding years is as follows (in thousands):

2016	$	1,100
2017		458
Total	$	1,558

In connection with the acquisition of Capitol, the Partnership incurred acquisition costs of approximately $3.5 million which are included in selling, general and administrative expenses in the accompanying consolidated statement of operations for the year ended December 31, 2015.

Supplemental Pro Forma Information—Revenues and net income not included in the Partnership’s consolidated operating results for Warren from January 1, 2015 through January 7, 2015, the acquisition date, were immaterial. Accordingly, the supplemental pro forma information for the year ended December 31, 2015 is consistent with the amounts reported in the accompanying consolidated statement of operations for the year ended December 31, 2015. As the acquisition transitioned the Revere Terminal from a formerly leased facility to an owned facility, the transaction did not have a material impact on the Partnership’s consolidated financial statements.

The following unaudited pro forma information for 2014 presents the consolidated results of operations of the Partnership as if the acquisition of Warren occurred at the beginning of 2014, with pro forma adjustments to give effect to intercompany sales and certain other adjustments. The following unaudited pro forma information for 2015 and 2014 presents the consolidated results of operations of the Partnership as if the acquisition of Capitol occurred at the beginning of each period presented, with pro forma adjustments to give effect to certain adjustments (in thousands, except per unit data):

	Year Ended December 31,
	2015		2014
Sales	$	10,540,275	$	19,303,900
Net income attributable to Global Partners LP	$	47,555	$	85,058
Net income per limited partner unit, basic	$	1.24	$	2.89
Net income per limited partner unit, diluted	$	1.23	$	2.88

Pro forma information for Warren for the year ended December 31, 2014 was based on unaudited revenues and net income. Pro forma information for Capitol for the period from January 1, 2015 through May 31, 2015 and for the year ended December 31, 2014 was estimated based on unaudited annual revenues and net income.

Warren’s revenues and net income included in the Partnership’s consolidated operating results from January 7, 2015, the acquisition date, through the year ended December 31, 2015 were $1.1 billion and $23.0 million, respectively. Capitol’s revenues and net income included in the Partnership’s consolidated operating results from June 1, 2015, the acquisition date, through the year ended December 31, 2015 were $0.2 billion and $6.2 million, respectively.

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Derivative Financial Instruments

12 Months Ended

Dec. 31, 2015

Derivative Financial Instruments

Derivative Financial Instruments

Note 4. Derivative Financial Instruments

The following table summarizes the notional values related to the Partnership’s derivative instruments outstanding at December 31, 2015:

	Units (1)		Unit of Measure
Exchange-Traded Derivatives
Long		37,785	Thousands of barrels
Short		(44,135)	Thousands of barrels
OTC Derivatives (Petroleum/Ethanol)
Long		7,840	Thousands of barrels
Short		(8,073)	Thousands of barrels
OTC Derivatives (Natural Gas)
Long		9,919	Thousands of decatherms
Short		(9,939)	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)	$	0.7	Millions of Canadian dollars
	$	0.5	Millions of U.S. dollars

(1) Number of open positions and gross notional values do not measure the Partnership’s risk of loss, quantify risk or represent assets or liabilities of the Partnership, but rather indicate the relative size of the derivative instruments and are used in the calculation of the amounts to be exchanged between counterparties upon settlements.

(2) All‑in forward rate Canadian dollars $1.3828 to USD $1.00.

Fair Value Hedges

The Partnership’s fair value hedges include exchange-traded futures contracts and OTC derivative contracts that are hedges against inventory with specific futures contracts matched to specific barrels. The change in fair value of these futures contracts and the change in fair value of the underlying inventory generally provide an offset to each other in the consolidated statement of operations.

The following table presents the gains and losses from the Partnership’s derivative instruments involved in fair value hedging relationships recognized in the consolidated statements of operations for the years ended December 31 (in thousands):

	Statement of Gain (Loss)
	Recognized in Income on	December 31,
	Derivatives	2015		2014		2013
Derivatives in fair value hedging relationship
Exchange-traded futures contracts and OTC derivative contracts for petroleum commodity products	Cost of sales	$	151,344	$	139,473	$	(18,231)
Hedged items in fair value hedge relationship
Physical inventory	Cost of sales	$	(158,987)	$	(141,699)	$	17,949

Cash Flow Hedges

The Partnership’s cash flow hedges currently include interest rate swaps and an interest rate cap that are hedges of variability in forecasted interest payments due to changes in the interest rate on LIBOR-based borrowings, a summary of which includes the following designations:

· 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%.  

In the aggregate, these hedging instruments have historically been effective in hedging the variability in interest payments due to changes in the one month LIBOR swap curve or rate with respect to $300.0 million of one month LIBOR based borrowings on the credit facility.

In June 2014 and as a result of the issuance of the Partnership’s $375.0 million aggregate principal amount of its 6.25% senior notes due 2022 (see Note 8), the Partnership determined that maintaining an excess of $300.0 million in principal of outstanding floating-rate debt was no longer probable. Therefore, the Partnership elected to de-designate its interest rate cap and discontinued the related hedge accounting for this instrument. Accordingly, at December 31, 2015, the Partnership had in place two interest rate swap agreements which are hedging $200.0 million of variable rate debt, both of which continue to be accounted for as cash flow hedges. The interest rate cap is not currently in a hedging relationship. Accordingly, all changes in fair value of this instrument subsequent to the date of de-designation are recorded in the consolidated statement of operations through interest expense.

The following table presents the amount of gains and losses from the Partnership’s derivative instruments designated in cash flow hedging relationships recognized in the consolidated statements of operations and partners’ equity for the years ended December 31 (in thousands):

							Location of Gain (Loss)
	Amount of Gain (Loss)						Reclassified from	Amount of Gain (Loss)
	Recognized in						Accumulated Other	Reclassified from Other
	Other Comprehensive						Comprehensive Income into	Comprehensive Income into
Derivatives Designated in	Income on Derivatives (Effective Portion)						Income (Effective Portion)	Income (Effective Portion)
Cash Flow Hedging Relationship	2015		2014		2013			2015		2014		2013
Interest rate collar	$	—	$	—	$	1,868	Interest expense	$	—	$	—	$	—
Interest rate swaps		3,353		2,766		2,071	Interest expense		—		—		—
Interest rate cap (1)		(17)		(8)		(9)	Interest expense		—		—		—
Total	$	3,336	$	2,758	$	3,930		$	—	$	—	$	—

(1) The interest rate cap was de-designated as a cash flow hedge in June 2014. Prepaid interest rate caplet amounts recognized in accumulated other comprehensive income up until the date of de-designation have been frozen in partner’s equity as of the de-designation date and are being amortized to income through the tenor of the interest rate cap instrument. The change in the fair value of the interest rate cap following de-designation is reflected in earnings and was immaterial for the years ended December 31, 2015 and 2014. As of December 31, 2015, the remaining unamortized prepaid interest rate caplets were $0.3 million and will be amortized over the remaining life for the interest rate cap which expires in April 2016.

The amount of gain (loss) recognized in income as ineffectiveness for derivatives designated in cash flow hedging relationships was $0 for the years ended December 31, 2015, 2014 and 2013.

Derivatives Not Accounted for as Hedges

The following table presents the gains and losses from the Partnership’s derivative instruments not involved in a hedging relationship recognized in the consolidated statements of operations for the years ended December 31 (in thousands):

	Statement of Gain (Loss)
Derivatives not designated as	Recognized in	December 31,
hedging instruments	Income on Derivatives	2015		2014		2013
Commodity contracts	Cost of sales	$	5,930	$	18,894	$	11,819
Forward foreign currency contracts	Cost of sales		191		25		(162)
Total		$	6,121	$	18,919	$	11,657

Commodity Contracts and Other Derivative Activity

The Partnership’s commodity contract derivatives and other derivative activity include: (i) exchange-traded derivative contracts that are hedges against inventory and either do not qualify for hedge accounting or are not designated in a hedge accounting relationship, (ii) exchange-traded derivative contracts used to economically hedge physical forward contracts, (iii) financial forward and OTC swap agreements used to economically hedge physical forward contracts and (iv) the derivative instruments under the Partnership’s controlled trading program. The Partnership does not take the normal purchase and sale exemption available under ASC 815 for its physical forward contracts.

The following table presents the fair value of each classification of the Partnership’s derivative instruments and its location in the consolidated balance sheets at December 31, 2015 and 2014 (in thousands):

		December 31, 2015
		Derivatives		Derivatives Not
		Designated as		Designated as
		Hedging		Hedging
	Balance Sheet Location	Instruments		Instruments		Total
Asset Derivatives:
Exchange-traded derivative contracts	Broker margin deposits	$	83,645	$	11,722	$	95,367
Forward derivative contracts (1)	Derivative assets		—		66,099		66,099
Forward foreign currency contracts	Other assets		—		10		10
Interest rate cap contract	Other assets		—		—		—
Total asset derivatives		$	83,645	$	77,831	$	161,476
Liability Derivatives:
Forward derivative contracts (1)	Derivative liabilities	$	—	$	31,911	$	31,911
Interest rate swap contracts	Other long-term liabilities		—		3,343		3,343
Total liability derivatives		$	—	$	35,254	$	35,254

		December 31, 2014
		Derivatives		Derivatives Not
		Designated as		Designated as
		Hedging		Hedging
	Balance Sheet Location	Instruments		Instruments		Total
Asset Derivatives:
Exchange-traded derivative contracts	Broker margin deposits	$	30,600	$	90,890	$	121,490
Forward derivative contracts (1)	Derivative assets		—		83,826		83,826
Forward foreign currency contracts	Other assets		—		9		9
Interest rate cap contract	Other assets		—		17		17
Total asset derivatives		$	30,600	$	174,742	$	205,342
Liability Derivatives:
Forward derivative contracts (1)	Derivative liabilities	$	—	$	58,507	$	58,507
Interest rate swap contracts	Other long-term liabilities		—		6,696		6,696
Total liability derivatives		$	—	$	65,203	$	65,203

(1) Forward derivative contracts include the Partnership’s petroleum and ethanol physical and financial forwards and OTC swaps.

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 to the Partnership’s exchange-traded and OTC derivative contracts, but the Partnership has no current reason to expect any material nonperformance by any of these counterparties. Exchange-traded derivative 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”), Chicago Mercantile Exchange (“CME”) and IntercontinentalExchange (“ICE”) derivative transactions and the right of offset exists with these financial institutions under master netting agreements. Accordingly, the fair value of the Partnership’s exchange-traded derivative instruments is presented on a net basis in the consolidated balance sheets. Exposure on OTC derivatives is limited to the amount of the recorded fair value as of the balance sheet dates.

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Income Taxes

12 Months Ended

Dec. 31, 2015

Income Taxes

Income Taxes

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:

	2015		2014		2013
Federal statutory income tax rate	35.0	%	34.0	%	34.0	%
State income tax rate, net of federal tax benefit	0.7	%	0.7	%	0.9	%
Foreign income tax	0.6	%	0.1	%	—	%
Partnership income not subject to tax	(40.8)	%	(34.0)	%	(32.9)	%
Effective income tax rate	(4.5)	%	0.8	%	2.0	%

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

	2015		2014		2013
Current:
Federal	$	110	$	(91)	$	(59)
State		1,388		877		542
Foreign		253		188		—
Total current		1,751		974		483
Deferred:
Federal		(1,298)		948		442
State		(2,326)		(959)		(106)
Total deferred		(3,624)		(11)		336
Total	$	(1,873)	$	963	$	819

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

	2015		2014
Deferred Income Tax Assets
Accounts receivable allowances	$	2,097	$	413
Environmental liability		17,814		4,211
Asset retirement obligation		3,132		1,490
Intangible assets		—		114
Deferred rent		40		—
UNICAP		747		663
Other		4,477		44
Federal net operating loss carryforwards		13,930		14,203
State net operating loss carryforwards		2,684		1,537
Federal tax credit carryforward		761		13
Total deferred tax assets, gross		45,682		22,688
Valuation allowance		(975)		—
Total deferred tax assets, net	$	44,707	$	22,688
Deferred Income Tax Liabilities
Property and equipment	$	(104,798)	$	(30,041)
Land		(11,527)		(5,605)
Intangible assets		(13,218)		—
Total deferred tax liabilities	$	(129,543)	$	(35,646)
Net deferred tax assets (liabilities)	$	(84,836)	$	(12,958)

The increase in net deferred tax assets and liabilities during 2015 is primarily due to the January 2015 acquisition of Warren which, for federal income tax purposes, was deemed to be a stock purchase and, therefore, the historical tax basis is the assets acquired and liabilities assumed carried over to the Partnership upon acquisition. New deferred tax assets and liabilities were created based on the comparison of the historical tax basis to the fair value book basis.

At December 31, 2015, GMG had federal and state net operating loss carryforwards of approximately $38.5 million and $54.6 million, respectively, which will begin to expire in 2030 and 2016, 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.

At December31, 2015, the Partnership had $73.3million of net deferred tax liabilities (consisting of the $84.8million total net deferred tax liability less the $11.5million deferred tax liability relating to land discussed below) relating to property and equipment, net operating loss carryforwards, tax credit carryforwards and other temporary differences, certain of which are available to reduce income taxes in future years. The Partnership recognizes deferred tax assets to the extent that the recoverability of these assets satisfy the “more likely than not” criteria in accordance with the FASB’s guidance regarding income taxes. 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 and reversal of existing taxable temporary differences, that a portion of these assets will not be realized in a future period. The valuation allowance increased by approximately $1.0million as of December31, 2015, primarily due to state net operating loss carryforwards.

At December 31, 2015, the Partnership also had an $11.5 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 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):

	2015		2014		2013
Income before income tax expense	$	41,391	$	117,943	$	41,872
Non—taxable income		(48,861)		(117,465)		(41,640)
Income subject to income tax expense	$	(7,470)	$	478	$	232

The Partnership made approximately $2.8 million, $0.7million and $0.3million in income tax payments during 2015, 2014 and 2013, 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 2012.

At December 31, 2015 and 2014, the Partnership had gross-tax effected unrecognized tax benefits of $0.1 million and $0, respectively, of which none would favorably impact the effective tax rate if recognized. The FASB’s accounting guidance for income taxes clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements by prescribing a minimum recognition threshold and measurement of a tax position taken or expected to be taken in a tax return. 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, 2015 (tax years ended December 31, 2015, 2014 and 2013). 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. The Partnership classifies interest and penalties related to income taxes as components of its provision for income taxes, and the amount of interest and penalties recorded in the accompanying balance sheets as of December 31, 2015 and 2014 and in the accompanying statements of operations for the years ended December 31, 2015, 2014 and 2013 were immaterial. The Partnership does not expect any material changes in the amount of unrecognized tax benefits over the next twelve months.

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Property and Equipment

12 Months Ended

Dec. 31, 2015

Property and Equipment

Property and Equipment

Note 6. Property and Equipment

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

	2015		2014
Buildings and improvements	$	992,917	$	667,172
Land		450,045		288,929
Fixtures and equipment		40,946		26,577
Construction in process		67,080		66,119
Capitalized internal use software		18,852		7,530
Total property and equipment		1,569,840		1,056,327
Less accumulated depreciation		327,157		231,276
Total	$	1,242,683	$	825,051

The increase of approximately $417.6 million in total property and equipment at December 31, 2015 was primarily due to the Partnership’s 2015 acquisitions of Warren, Capitol and the Revere Terminal, which contributed to $433.2 million of acquired property and equipment (see Note 3).

At December31, 2015 and 2014, construction in process included $30.5 million related to the Partnership’s ethanol plant acquired from Cascade Kelly in 2013. The Partnership has begun to take steps to utilize this location. This measure is substantially related to cleaning of tanks and associated infrastructure and is expected to be completed in the third quarter of 2016. Therefore, as of December31, 2015 and 2014, the recorded value of the ethanol plant is included in construction in process. After the plant has been placed into service, depreciation will commence. Construction in process in 2015 also included $23.1million in costs associated with the Partnership’s terminals, which primarily included dock expansion, tank construction projects, rail expansion and improvements, various upgrades at certain terminals and investments in information technology, and $13.5million in costs related to the Partnership’s gasoline stations. At December 31, 2014, construction also included $30.8million in costs associated with the Partnership’s crude oil activities, primarily tank construction projects, rail expansion and improvements, various upgrades at certain terminals and investments in information technology, and $4.8million in costs related to the Partnership’s gasoline stations.

As part of continuing operations, the Partnership may periodically divest certain gasoline stations. The gain or loss on the sale, representing cash proceeds less net book value of assets at disposition, is recorded in (loss) gain on sale and disposition of assets in the accompanying consolidated statements of operations and amounted to ($2.1 million), ($2.2 million) and $1.3 million for the years ended December 31, 2015, 2014 and 2013, respectively. Additionally, in conjunction with the periodic divestiture of gasoline stations, the Partnership may classify certain gasoline station assets as held-for-sale. The Partnership classified $7.4 million and $3.3 million at December31, 2015 and 2014, respectively, as assets held-for-sale which are included in property and equipment in the accompanying balance sheets.

Depreciation

Depreciation expense allocated to cost of sales was approximately $94.8 million, $61.4 million and $55.6 million for the years ended December 31, 2015, 2014 and 2013, respectively. The increase in 2015 compared to 2014 and 2013 was due primarily to the January 2015 acquisition of Warren and the June 2015 acquisition of Capitol.

Depreciation expense allocated to selling, general and administrative expenses was approximately $7.5 million, $6.1 million and $2.3 million for the years ended December 31, 2015, 2014 and 2013, respectively.The increase in 2015 compared to 2014 and 2013 was due primarily to the January 2015 acquisition of Warren and the June 2015 acquisition of Capitol. The increase in 2014 compared to 2013 was due primarily to a full year of depreciation related to the Partnership’s February 2013 acquisitions of Basin Transload and Cascade Kelly.

There were no fully depreciated assets written off for the years ended December 31, 2015 and 2014.

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Goodwill and Intangible Assets

12 Months Ended

Dec. 31, 2015

Goodwill and Intangible Assets

Goodwill and Intangible Assets

Note 7. Goodwill and Intangible Assets

There were no changes to the Partnership’s goodwill during the year ended December 31, 2014. The following table presents changes in goodwill by segment during the year ended December 31, 2015 (in thousands):

	Goodwill Allocated to
	Wholesale		GDSO
	Reporting		Reporting
	Unit		Unit		Total
Balance at December 31, 2014	$	121,752	$	32,326	$	154,078
Acquisition of Warren		—		186,437		186,437
Acquisition of Capitol		—		94,854		94,854
Balance at December 31, 2015	$	121,752	$	313,617	$	435,369

Intangible assets consisted of the following (in thousands):

	Gross				Net
	Carrying		Accumulated		Intangible		Amortization
	Amount		Amortization		Assets		Period
At December 31, 2015
Intangible assets subject to amortization:
Terminalling services	$	26,365	$	(11,087)	$	15,278	20 years
Customer relationships		43,986		(39,691)		4,295	2-15 years
Supply contracts		77,771		(24,412)		53,359	5-15 years
Favorable leasehold interests		2,960		(794)		2,166	2-5 years
Brand incentive program		1,445		(1,117)		328	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		(511)		268	20 years
Total intangible assets	$	155,694	$	(80,000)	$	75,694
At December 31, 2014
Intangible assets subject to amortization:
Terminalling services	$	26,365	$	(9,752)	$	16,613	20 years
Customer relationships		43,986		(35,996)		7,990	2-15 years
Supply contracts		39,646		(16,345)		23,301	5-15 years
Brand incentive program		1,445		(879)		566	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	$	(65,707)	$	48,902

The increase in total intangible assets in 2015 compared to 2014 was due primarily to the January 2015 acquisition of Warren and, to a lesser extent, the June 2015 acquisition of Capitol. The aggregate amortization expense was approximately $13.5 million, $18.9 million and $19.2 million for the years ended December 31, 2015, 2014 and 2013, respectively. The decrease in amortization expense in 2015 compared to 2014 and 2013 was due to intangible assets that became fully amortized during 2015.

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

2016	$	11,011
2017		10,025
2018		9,477
2019		9,477
2020		9,176
Thereafter		26,528
Total intangible assets	$	75,694

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Debt

12 Months Ended

Dec. 31, 2015

Debt

Debt

Note 8. Debt

Credit Agreement

As of December 31, 2015, certain subsidiaries of the Partnership, as borrowers, and the Partnership and certain of its subsidiaries, as guarantors, had a $1.775billion senior secured credit facility (the “Credit Agreement”).On February 24, 2016, the Partnership and certain of its subsidiaries entered into the fifth amendment to the Credit Agreement. This amendment reflects the Partnership’s voluntary election to reduce the maximum aggregate amount available under the Credit Agreement to $1.475 billion (see “—Amendment to Credit Agreement” below). The Credit Agreement will mature on April 30, 2018.

As of December 31, 2015, 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  $775.0 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 $300.0million, in the aggregate. 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.

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.

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 Loan Parties are permitted to sell or transfer any account receivable to an AR Buyer only pursuant to the provisions provided 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 minimis.

Availability under the working capital revolving credit facility is subject to a borrowing base which is redetermined from time to time 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.

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). 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).

The average balance under the working capital revolving credit facility was $234.1 million and $208.4 million for the years ended December 31, 2015 and 2014, respectively, and the average balance under the revolving credit facility was $382.2 million and $353.2 million for the years ended December 31, 2015 and 2014, respectively.  The average interest rates for the Credit Agreement were 3.6%, 3.7% and4.2% for the years ended December 31, 2015, 2014 and 2013, respectively.

As of December 31, 2015, the Partnership had two interest rate swaps, both of which were used to hedge the variability in interest payments under the Credit Agreement due to changes in LIBOR rates. See Note 2 and Note 4 for additional information on these cash flow hedges. Additionally, the Partnership has an interest rate cap that is hedging variable interest. The cap is not designated for accounting purposes.

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 current liability and a portion as a long-term liability. The portion classified as a long-term liability represents the amounts expected to be outstanding during the entire year based on an analysis of historical borrowings under the working capital revolving credit facility, the seasonality of borrowings, forecasted future working capital requirements and forward product curves, and because the Partnership has a multi-year, long-term commitment from its bank group. Accordingly, at December 31, 2015, the Partnership estimated working capital revolving credit facility borrowings will equal or exceed $150.0million over the next twelve months and, therefore, classified $98.1million as the current portion at December 31, 2015, representing the amount the Partnership expects to pay down over the next twelve months. The long-term portion of the working capital revolving credit facility was $150.0 million and $100.0 million at December 31, 2015 and 2014, respectively, and the current portion was $98.1 million and $0,  at December 31, 2015 and 2014, respectively. The increase in total borrowings under the working capital revolving credit facility of $148.1 million from December 31, 2014 was primarily due to cash used in operating assets and liabilities during the year. Inventory increased due to higher volume stored, and accounts payable and receivables decreased as a result of declining prices during the year.

As of December 31, 2015, the Partnership had total borrowings outstanding under the Credit Agreement of $517.1 million, including $269.0 million outstanding on the revolving credit facility. In addition, the Partnership had outstanding letters of credit of $63.7 million. Subject to borrowing base limitations, the total remaining availability for borrowings and letters of credit was $1.2 billion and $1.4 billion at December 31, 2015 and 2014, 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 subsidiaries with the exception of Basin Transload.

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 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, 2015. 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).

Amendment to Credit Agreement

On February 24, 2016, the Partnership and certain of its subsidiaries entered into the fifth amendment to the Credit Agreement (the “Fifth Amendment”). The Fifth Amendment includes certain modifications to the Credit Agreement to (i) amend the definition of “Total Combined Leverage Ratio” to permit for an increased maximum ratio of 5.50:1.00 through the first quarter of 2017 and 5.00:1.00 thereafter, (ii) amend the definition of “Applicable Revolver Rate” to align the pricing levels with the amended Total Combined Leverage Ratio maximum thresholds, (iii) increase the permitted level of asset Dispositions (as it is defined in the Credit Agreement) from $100.0 million to $150.0 million, and (iv) incorporate acknowledgement of and consent to the applicability of European Union Bank Recovery and Resolution Directive bail-in legislation. 

Unrelated to the foregoing modifications, the Fifth Amendment also reflects the Partnership’s voluntary election to reduce its working capital revolving credit facility from $1.0 billion to $900.0 million and its revolving credit facility from $775.0 million to $575.0 million, for a total available commitment of $1.475 billion.

6.25% Senior Notes

On June 19, 2014, the Partnership and GLP Finance Corp. (“GLP Finance” and, together with the Partnership, the “Issuers”) entered into a Purchase Agreement (the “Purchase Agreement”) with the Initial Purchasers (as defined therein) (the “Initial Purchasers”) pursuant to which the Issuers agreed to sell $375.0 million aggregate principal amount of the Issuers’ 6.25% senior notes due 2022 (the “6.25% Notes”) to the Initial Purchasers in a private placement exempt from the registration requirements under the Securities Act of 1933, as amended (the “Securities Act”). The 6.25% Notes were resold by the Initial Purchasers to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to persons outside the United States pursuant to Regulation S under the Securities Act.

The Purchase Agreement contained customary representations and warranties of the parties and indemnification and contribution provisions under which the Issuers and the subsidiary guarantors, on one hand, and the Initial Purchasers, on the other, agreed to indemnify each other against certain liabilities, including liabilities under the Securities Act. In addition, the Purchase Agreement required the execution of a registration rights agreement, described below, relating to the 6.25% Notes. Closing of the offering occurred on June 24, 2014.

Indenture

In connection with the private placement of the 6.25% Notes on June 24, 2014, the Issuers and the subsidiary guarantors and Deutsche Bank Trust Company Americas, as trustee, entered into an indenture (the “Indenture”).

The 6.25% Notes mature on July 15, 2022 with interest accruing at a rate of 6.25% per annum and payable semi-annually in arrears on January 15 and July 15 of each year, commencing January 15, 2015. The 6.25% Notes are guaranteed on a joint and several senior unsecured basis by each of the Issuers and the subsidiary guarantors to the extent set forth in the Indenture. Upon a continuing event of default, the trustee or the holders of at least 25% in principal amount of the 6.25% Notes may declare the 6.25% Notes immediately due and payable, except that an event of default resulting from entry into a bankruptcy, insolvency or reorganization with respect to the Partnership, any restricted subsidiary of the Partnership that is a significant subsidiary or any group of its restricted subsidiaries that, taken together, would constitute a significant subsidiary of the Partnership, will automatically cause the 6.25% Notes to become due and payable.

The Issuers have the option to redeem up to 35% of the 6.25% Notes prior to July 15, 2017 at a redemption price (expressed as a percentage of principal amount) of 106.25% plus accrued and unpaid interest, if any. The Issuers have the option to redeem the 6.25% Notes, in whole or in part, at any time on or after July 15, 2017, at the redemption prices of 104.688% for the twelve-month period beginning on July 15, 2017, 103.125% for the twelve-month period beginning July 15, 2018, 101.563% for the twelve-month period beginning July 15, 2019, and 100.0% beginning on July 15, 2020 and at any time thereafter, together with any accrued and unpaid interest to the date of redemption. In addition, before July 15, 2017, the Issuers may redeem all or any part of the 6.25% Notes at a redemption price equal to the sum of the principal amount thereof, plus a make whole premium at the redemption date, plus accrued and unpaid interest, if any, to the redemption date. The holders of the notes may require the Issuers to repurchase the 6.25% Notes following certain asset sales or a Change of Control (as defined in the Indenture) at the prices and on the terms specified in the Indenture.

The Indenture contains covenants that will limit the Partnership’s ability to, among other things, incur additional indebtedness and issue preferred securities, make certain dividends and distributions, make certain investments and other restricted payments, restrict distributions by its subsidiaries, create liens, enter into sale-leaseback transactions, sell assets or merge with other entities. Events of default under the Indenture include (i) a default in payment of principal of, or interest or premium, if any, on, the 6.25% Notes, (ii) breach of the Partnership’s covenants under the Indenture, (iii) certain events of bankruptcy and insolvency, (iv) any payment default or acceleration of indebtedness of the Partnership or certain subsidiaries if the total amount of such indebtedness unpaid or accelerated exceeds $15.0 million and (v) failure to pay within 60 days uninsured final judgments exceeding $15.0 million.

Registration Rights Agreement

On June 24, 2014, the Issuers and the subsidiary guarantors entered into a registration rights agreement (the “Registration Rights Agreement”) with the Initial Purchasers in connection with the Issuers’ private placement of the 6.25% Notes. Under the Registration Rights Agreement, the Issuers and the subsidiary guarantors agreed to file and use commercially reasonable efforts to cause to become effective a registration statement relating to an offer to exchange the 6.25% Notes for an issue of SEC-registered notes with terms identical to the 6.25% Notes (except that the exchange notes are not subject to restrictions on transfer or to any increase in annual interest rate for failure to comply with the Registration Rights Agreement) that are registered under the Securities Act so as to permit the exchange offer to be consummated by the 360th day after June 24, 2014. The exchange offer was completed on April 21, 2015, and 100% of the 6.25% Notes were exchanged for SEC-registered notes.

7.00% Senior Notes

On June 1, 2015, the Issuers entered into a Purchase Agreement (the “7.00% Notes Purchase Agreement”) with the Initial Purchasers (as defined therein) (the “7.00% Notes Initial Purchasers”) pursuant to which the Issuers agreed to sell $300.0 million aggregate principal amount of the Issuers’ 7.00% senior notes due 2023 (the “7.00% Notes”) to the 7.00% Notes Initial Purchasers in a private placement exempt from the registration requirements under the Securities Act. The 7.00% Notes were resold by the 7.00% Notes Initial Purchasers to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to persons outside the United States pursuant to RegulationS under the Securities Act.

The 7.00% Notes Purchase Agreement contained customary representations and warranties of the parties and indemnification and contribution provisions under which the Issuers and the subsidiary guarantors, on one hand, and the 7.00% Notes Initial Purchasers, on the other, agreed to indemnify each other against certain liabilities, including liabilities under the Securities Act. In addition, the 7.00% Notes Purchase Agreement required the execution of a registration rights agreement, described below, relating to the 7.00% Notes. Closing of the offering occurred on June 4, 2015.

Indenture

In connection with the private placement of the 7.00% Notes on June 4, 2015 the Issuers and the subsidiary guarantors and Deutsche Bank Trust Company Americas, as trustee, entered into an indenture (the “7.00% Notes Indenture”).

The 7.00% Notes will mature on June 15, 2023 with interest accruing at a rate of 7.00% per annum and payable semi-annually in arrears on June 15 and December 15 of each year, commencing December 15, 2015. The 7.00% Notes are guaranteed on a joint and several senior unsecured basis by each of the Issuers and the subsidiary guarantors to the extent set forth in the 7.00% Notes Indenture. Upon a continuing event of default, the trustee or the holders of at least 25% in principal amount of the 7.00% Notes may declare the 7.00% Notes immediately due and payable, except that an event of default resulting from entry into a bankruptcy, insolvency or reorganization with respect to the Partnership, any restricted subsidiary of the Partnership that is a significant subsidiary or any group of its restricted subsidiaries that, taken together, would constitute a significant subsidiary of the Partnership, will automatically cause the 7.00% Notes to become due and payable.

The Issuers will have the option to redeem up to 35% of the 7.00% Notes prior to June 15, 2018 at a redemption price (expressed as a percentage of principal amount) of 107.00% plus accrued and unpaid interest, if any. The Issuers have the option to redeem the 7.00% Notes, in whole or in part, at any time on or after June 15, 2018, at the redemption prices of 105.250% for the twelve-month period beginning June 15, 2018, 103.500% for the twelve-month period beginning June 15, 2019, 101.750% for the twelve-month period beginning June 15, 2020, and 100.0% beginning June 15, 2021 and at any time thereafter, together with any accrued and unpaid interest to the date of redemption. In addition, before June 15, 2018, the Issuers may redeem all or any part of the 7.00% Notes at a redemption price equal to the sum of the principal amount thereof, plus a make whole premium, plus accrued and unpaid interest, if any, to the redemption date. The holders of the 7.00% Notes may require the Issuers to repurchase the 7.00% Notes following certain asset sales or a Change of Control (as defined in the 7.00% Notes Indenture) at the prices and on the terms specified in the 7.00% Notes Indenture.

The 7.00% Notes Indenture contains covenants that will limit the Partnership’s ability to, among other things, incur additional indebtedness and issue preferred securities, make certain dividends and distributions, make certain investments and other restricted payments, restrict distributions by its subsidiaries, create liens, enter into sale-leaseback transactions, sell assets or merge with other entities. Events of default under the 7.00% Notes Indenture include (i) a default in payment of principal of, or interest or premium, if any, on, the 7.00% Notes, (ii) breach of the Partnership’s covenants under the 7.00% Notes Indenture, (iii) certain events of bankruptcy and insolvency, (iv) any payment default or acceleration of indebtedness of the Partnership or certain subsidiaries if the total amount of such indebtedness unpaid or accelerated exceeds $50.0million and (v) failure to pay within 60 days uninsured final judgments exceeding $50.0million.

Registration Rights Agreement

On June 4, 2015, the Issuers and the subsidiary guarantors entered into a registration rights agreement (the “7.00% Notes Registration Rights Agreement”) with the 7.00% Notes Initial Purchasers in connection with the Issuers’ private placement of the 7.00% Notes. Under the 7.00% Notes Registration Rights Agreement, the Issuers and the subsidiary guarantors agreed to file and use commercially reasonable efforts to cause to become effective a registration statement relating to an offer to exchange the 7.00% Notes for an issue of SEC-registered notes with terms identical to the 7.00% Notes (except that the exchange notes are not subject to restrictions on transfer or to any increase in annual interest rate for failure to comply with the 7.00% Notes Registration Rights Agreement) that are registered under the Securities Act so as to permit the exchange offer to be consummated by the 420th day after June 4, 2015. The exchange offer was completed on October 22, 2015, and 100% of the 7.00% Notes were exchanged for SEC-registered notes.

Line of Credit.

On December 9, 2013, Basin Transload entered into a line of credit facility which allows for borrowings by Basin Transload of up to $10.0 million on a revolving basis. The facility had an outstanding balance of $0 and $0.7 million at December 31, 2015 and 2014, respectively. The facility, which expired on February 9, 2016, was secured by substantially all of the assets of Basin Transload and was not guaranteed by the Partnership or any of its wholly owned subsidiaries.

Financing Obligation

In connection with the Capitol acquisition on June1, 2015, (see Note3) the Partnership assumed a financing obligation of $89.6million associated with two sale-leaseback transactions by Capitol for 53 leased sites that did not meet the criteria for sale accounting. During the term of these leases, which expire in May 2028 and September 2029, in lieu of recognizing lease expense for the lease rental payments, the Partnership incurs interest expense associated with the financing obligation. Interest expense of approximately $5.6million was recorded for the year ended December 31, 2015 and included in interest expense in the accompanying statement of operations. The financing obligation will amortize through expiration of the lease based upon the lease rental payments which were $5.4 million for the year ended December 31, 2015. The financing obligation balance outstanding at December 31, 2015 was $89.8 million.

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 other financing arrangements. The Partnership capitalized deferred financing fees of $19.0 million and $24.0 million at December 31, 2015 and 2014, respectively.

Unamortized fees related to the Credit Agreement are included in other current assets and other long-term assets and amounted to $11.2million and $16.0million at December 31, 2015 and 2014, respectively. Unamortized fees related to the senior notes are presented as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts and amounted to $7.8million and $8.0million at December 31, 2015 and 2014, respectively. As of December31, 2015, the Partnership adopted ASU 2015-03, “Interest-Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs,” See Note 2.

Amortization expense of approximately $5.9 million, $5.6 million and $6.9 million for the years ended December 31, 2015, 2014 and 2013, respectively, are included in interest expense in the accompanying consolidated statements of operations.

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Environmental Liabilities, Asset Retirement Obligations and Renewable Identification Numbers

12 Months Ended

Dec. 31, 2015

Environmental Liabilities and Renewable Identification Numbers (RINs)

Environmental Liabilities, Asset Retirement Obligations and Renewable Identification Numbers (RINs)

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.

In connection with the June 2015 acquisition of retail gasoline stations from Capitol (see Note 3), the Partnership assumed certain environmental liabilities, including future remediation activities required by applicable federal, state or local law or regulation at certain of the retail gasoline stations owned by Capitol. Certain environmental remediation obligations at most of the acquired retail gasoline station assets from Capitol are being funded by third parties who assumed certain liabilities in connection with Capitol’s acquisition of these assets from ExxonMobil Corporation (“ExxonMobil”) in 2009 and 2010 and, therefore, cost estimates for such obligations at these stations are not included in this estimate. As a result, the Partnership initially recorded, on an undiscounted basis, a total environmental liability of approximately $0.3 million for those locations not covered by third parties.

In connection with the January 2015 acquisition of the Revere Terminal (see Note 3), the Partnership assumed certain environmental liabilities, including certain ongoing environmental remediation efforts. As a result, the Partnership initially recorded, on an undiscounted basis, a total environmental liability of approximately $3.1 million.

In connection with the January 2015 acquisition of Warren (see Note 3), the Partnership assumed certain environmental liabilities, including certain ongoing environmental remediation efforts at certain of the retail gasoline stations owned by Warren and future remediation activities required by applicable federal, state or local law or regulation. As a result, the Partnership initially recorded, on an undiscounted basis, a total environmental liability of approximately $36.5 million.

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

In connection with the March 2012 acquisition of Alliance, the Partnership assumed Alliance’s environmental liabilities, including ongoing environmental remediation at certain of the retail gasoline 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 initially 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 initially 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 initially recorded, on an undiscounted basis, a total environmental liability of approximately $1.5 million.

In addition to the above-mentioned environmental liabilities related to the Partnership’s retail gasoline stations, the Partnership retains environmental obligations associated with certain gasoline stations that the Partnership has sold.

The following table presents a summary roll forward of the Partnership’s environmental liabilities at December 31, 2015 (in thousands):

	Balance at								Other		Balance at
	December 31,		Additions		Payments in		Dispositions		Adjustments		December 31,
Environmental Liability Related to:	2014		2015		2015		2015		2015		2015
Retail gasoline stations	$	35,792	$	36,767	$	(3,535)	$	(75)	$	(498)	$	68,451
Terminals		1,771		3,074		(63)		—		—		4,782
Total environmental liabilities	$	37,563	$	39,841	$	(3,598)	$	(75)	$	(498)	$	73,233
Current portion	$	3,101									$	5,350
Long-term portion		34,462										67,883
Total environmental liabilities	$	37,563									$	73,233

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 obligations through divestures of sites and the possibility of existing legal claims giving rise to additional claims. Dispositions generally represent relief of legal obligations through the sale of the related property with no retained obligation. 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 renewable fuel for the purpose of tracking its production, use, and trading as required by the U.S. Environmental Protection Agency’s (“EPA”) Renewable Fuel Standard that originated with the Energy Policy Act of 2005 and modified by the Energy Independence and Security Act of 2007. To evidence that the required volume of renewable fuel is blended with gasoline and diesel motor vehicle fuels, obligated parties must retire sufficient RINs to cover their Renewable Volume Obligation (“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 and a small amount of blending operations at certain facilities. 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 the RVO is a calendar year and the settlement of the RVO typically occurs by March 31 of the following year, the settlement of the RVO can occur, under certain EPA deferral actions, more than one year after the close of the compliance period.

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 that the Partnership does not have a sufficient number of RINs to satisfy the RVO 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. The Partnership’s RVO deficiency was $0.4 million and $0.3 million at December 31, 2015 and 2014, respectively.

The Partnership may enter into RIN forward purchase and sales commitments. Total losses at December 31, 2015 and 2014 from firm non-cancellable commitments were immaterial.

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Trustee Taxes and Accrued Expenses and Other Current Liabilities

12 Months Ended

Dec. 31, 2015

Trustee Taxes and Accrued Expenses and Other Current Liabilities

Trustee Taxes and Accrued Expenses and Other Current Liabilities

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):

	2015		2014
Barging transportation, product storage and other ancillary cost accruals	$	13,385	$	19,843
Employee compensation		16,098		26,827
Accrued interest		12,524		12,839
Customer Advance		—		12,000
RIN and RVO deficiency		367		253
Other		17,954		11,058
Total	$	60,328	$	82,820

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 $95.3 million at December31, 2015, which consisted of $55.4 million related to an ethanol credit and $39.9 million in various pass‑through taxes collected on behalf of taxing authorities. Trustee taxes payable at December31, 2014 of $105.7 million consisted of $55.4 million related to an ethanol credit and $50.3 million in various pass‑through taxes collected on behalf of taxing authorities.

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Employee Benefit Plans with Related Party

12 Months Ended

Dec. 31, 2015

Employee Benefit Plans with Related Party

Employee Benefit Plans with Related Party

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.

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 GMG 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 $2.4 million, $2.0 million and $1.8 million for the years ended December 31, 2015, 2014 and 2013, respectively, which are included in selling, general and administrative expenses in the accompanying statements of operations.

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.

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

	December 31,  2015
	Global		GMG
	Pension Plan		Pension Plan		Total
Projected benefit obligation	$	16,338	$	4,593	$	20,931
Fair value of plan assets		13,481		3,405		16,886
Net unfunded pension liability	$	2,857	$	1,188	$	4,045

	December 31,  2014
	Global		GMG
	Pension Plan		Pension Plan		Total
Projected benefit obligation	$	18,333	$	5,282	$	23,615
Fair value of plan assets		14,545		3,478		18,023
Net unfunded pension liability	$	3,788	$	1,804	$	5,592

Total actual return on plan assets was ($0.2 million) and $1.2 million in 2015 and 2014, respectively.

The following presents the components of the net periodic change in benefit obligation for the Pension Plans for the years ended December 31 (in thousands):

	2015		2014		2013
Benefit obligation at beginning of year	$	23,615	$	19,245	$	23,073
Interest cost		801		804		730
Actuarial (gain) loss		(1,925)		5,151		(2,419)
Benefits paid		(1,559)		(1,585)		(2,139)
Benefit obligation at end of year	$	20,932	$	23,615	$	19,245

The following presents the weighted-average actuarial assumptions used in determining each plan’s annual pension expense for the years ended December 31:

	Global Pension Plan			GMG Pension Plan
	2015	2014	2013	2015	2014	2013
Discount rate	4.0%	3.6%	4.4%	4.3%	3.6%	4.4%
Expected return on plan assets	7.0%	7.5%	7.5%	7.0%	7.0%	7.0%

The discount rates were selected by performing a cash flow/bond matching analysis based on the Citigroup Above‑Median Pension Discount Curve. 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 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 following presents the Pension Plans’ benefits as of December 31, 2015 expected to be paid in each of the next five fiscal years and in the aggregate for the next five fiscal years thereafter (in thousands):

2016	$	2,001
2017		2,436
2018		833
2019		808
2020		1,334
2021—2025		4,933
Total	$	12,345

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 $0.6 million, $0.2 million and $0.5 million in 2015, 2014 and 2013, respectively.

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Long-Term Incentive Plan

12 Months Ended

Dec. 31, 2015

Long-Term Incentive Plan

Long-Term Incentive Plan

Note 12. Long-Term Incentive Plan

The Partnership has a Long Term Incentive Plan, as amended (the “LTIP”), whereby a total of 4,300,000 common units were authorized for delivery with respect to awards under the LTIP. The 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 LTIP allows for the award of options, unit appreciation rights, restricted units, phantom units, distribution equivalent rights, unit awards and substitute awards.

Awards granted under the LTIP are authorized by the Compensation Committee of the board of directors of the General Partner (the “Committee”) from time to time. Additionally and in accordance with the LTIP, the Committee established a “CEO Authorized LTIP” program pursuant to which the Chief Executive Officer (“CEO”) may grant awards of phantom units without distribution equivalent rights to employees of the General Partner and the Partnership’s subsidiaries, other than named executive officers. The CEO Authorized LTIP program was approved for three consecutive calendar years commencing January 1, 2014, subject to modification or earlier termination by the Committee. During each calendar year of the program, the CEO is authorized to grant awards of up to an aggregate amount of $2.0 million of phantom units payable in common units upon vesting, with unused dollar amounts carrying over in the next year, and no individual grant may be made for an award valued at the time of grant of more than $550,000, unless otherwise previously approved by the Committee. Awards granted pursuant to the CEO Authorized LTIP generally would be for a term of six years and vest in equal tranches at the end of each of the fourth, fifth and sixth anniversary dates of the particular award.

Phantom Unit Awards

In 2013, the Committee granted a total of 498,112 phantom units under the 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. On December 31, 2014, a total of 10,266 of the awards granted to one employee and the non-employee directors vested and in January 2015, these phantom unit grants were settled.

In 2014, a total of 44,902 phantom units were granted to certain employees.

In 2015, a total of 76,893 phantom units were granted to certain employees and the non-employee directors.

The phantom units for these awards vest pursuant to the terms of the grant agreements. The Partnership currently intends and reasonably expects to issue and deliver the common units upon vesting.

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 above awards at their respective grant dates 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 awards, is recognized over the requisite service period. The requisite service period for the Partnership is from the grant date through the vesting dates described in the grant agreement. The Partnership recognizes 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 total compensation expense related to the above awards of $4.3 million, $3.5 million and $1.7 million for the years ended December 31, 2015, 2014 and 2013, respectively, which is included in selling, general and administrative expenses in the accompanying consolidated statements of operations. The total compensation cost related to the non-vested awards not yet recognized at December 31, 2015 was approximately $14.4 million and is expected to be recognized ratably over the remaining requisite service periods.

Status of Non‑Vested Units

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

		Weighted
	Number of	Average
	Non-vested	Grant Date
	Units	Fair Value
Outstanding non—vested units at December 31, 2013	498,112	$	39.29
Granted	44,902		39.34
Vested	(10,266)		39.29
Forfeited	—		—
Outstanding non—vested units at December 31, 2014	532,748		39.29
Granted	76,893		35.72
Vested	(13,921)		38.39
Forfeited	—		—
Outstanding non—vested units at December 31, 2015	595,720	$	38.85

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 authorized to acquire up to 1,242,427 of its common units in the aggregate over an extended period of time, consistent with the General Partner’s Obligations. 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 and economic and market conditions, applicable legal requirements and available liquidity. Since the Repurchase Program was implemented, the General Partner has repurchased 838,505 common units pursuant to the Repurchase Program for approximately $24.8 million, of which approximately $3.9 million was purchased during 2015.

Common units outstanding as reported in the accompanying consolidated financial statements at December 31, 2015 and 2014 excluded 403,922 and 390,602 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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Commitments and Contingencies

12 Months Ended

Dec. 31, 2015

Commitments and Contingencies

Commitments and Contingencies

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, 2015 (in thousands):

2016	$	2,816
2017		2,743
2018		2,644
2019		2,650
2020		2,297
Thereafter		13,840
Total	$	26,990

Total rent expense under the operating lease arrangements amounted to approximately $2.5 million, $2.7 million and $2.7 million for the years ended December 31, 2015, 2014 and 2013, 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.

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 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, 2015 (in thousands):

2016	$	14,984
2017		8,353
2018		723
2019		132
Total	$	24,192

Total rent expense reflected in cost of sales related to these operating leases were approximately $22.5 million, $31.5 million and $35.5 million for the years ended December 31, 2015, 2014 and 2013, respectively.

Leases of Gasoline Stations

The Partnership 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, 2015 (in thousands):

2016	$	29,432
2017		26,102
2018		23,365
2019		20,712
2020		18,236
Thereafter		98,193
Total	$	216,040

Total expenses under these operating lease arrangements amounted to approximately $29.4 million, $19.7 million and $17.7 million for the years ended December 31, 2015, 2014 and 2013, respectively. The increase in total expenses in 2015 compared to 2014 and 2013 was primarily due to the January 2015 acquisition of Warren and the June 2015 acquisition of Capitol.

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, 2015 was $368.4 million, net of accumulated depreciation of approximately $48.7 million. The following provides future minimum rental income under non‑cancellable operating leases associated with these properties at December 31, 2015 (in thousands):

2016	$	45,125
2017		23,781
2018		7,797
2019		1,212
2020		1,079
Thereafter		17,001
Total	$	95,995

Total rental income, which includes reimbursement of utilities and property taxes in certain cases, amounted to approximately $61.1 million, $42.5 million and $41.3 million for the years ended December 31, 2015, 2014 and 2013, respectively. The increase in rental income in 2015 compared to 2014 and 2013 was primarily due to the January 2015 acquisition of Warren and the June 2015 acquisition of Capitol.

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, 2015 (in thousands):

2016	$	59,625
2017		52,186
2018		45,968
2019		28,532
2020		2,257
Thereafter		608
Total	$	189,176

The minimum lease commitments for 2016 and 2017 are net of $10.8 million and $2.7 million, respectively, related to a contractual sub-lease arrangement that expires in 2017.

Total expenses under these operating lease arrangements amounted to approximately $57.7 million, $56.9 million and $28.9 million for the years ended December 31, 2015, 2014 and 2013, respectively.

Leases of Barges

The Partnership leases barges through various time charter 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, 2015 (in thousands):

2016	$	58,256
2017		45,854
2018		36,440
2019		12,223
2020		1,983
Total	$	154,756

Total expenses under these operating lease arrangements amounted to approximately $87.3 million, $60.6 million and $37.1 million for the years ended December 31, 2015, 2014 and 2013, respectively. The increase in expenses was due to the Partnership leasing more barges under time charters compared to previous periods.

Purchase 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, 2015, the Partnership has fulfilled all gallonage commitments. The following provides minimum volume purchase requirements at December 31, 2015 (in thousands of gallons):

2016	397,600
2017	331,900
2018	330,100
2019	327,700
2020	312,700
Thereafter	828,300
Total	2,528,300

Brand Fee Agreement

The Partnership entered into a brand fee agreement with ExxonMobil which entitles the Partnership to operate 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 gasoline stations acquired from ExxonMobil in 2010, 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, 2015 (in thousands):

2016	$	9,000
2017		9,000
2018		9,000
2019		9,000
2020		9,000
Thereafter		40,500
Total	$	85,500

Total expenses reflected in cost of sales related this agreement were approximately $9.0 million for each of the years ended December 31, 2015, 2014 and 2013.

Port of St. Helens Agreements—Land and Equipment

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, 2015 (in thousands):

2016	$	223
2017		223
2018		223
2019		223
2020		223
Thereafter		10,128
Total	$	11,243

Total rental expense was approximately $223,000,$222,000 and $180,000 for the years ended December 31, 2015, 2014 and 2013, respectively.

Other Commitments

In June 2014, the Partnership entered into a pipeline connection agreement with Meadowlark Midstream Company, LLC (“Meadowlark”) whereby Meadowlark would construct, own, operate and maintain a crude oil pipeline from its Divide County, North Dakota crude oil station to the Partnership’s Basin Transload crude oil storage facility in Columbus, North Dakota. In connection with the agreement, the Partnership is committed to a minimum take-or-pay throughput commitment of approximately $55.0 million over a seven–year period beginning after the commissioning of the pipeline which occurred in December of 2015. At December 31, 2015, the remaining commitment on the take-or-pay commitment was approximately $55.0 million.

In May 2014, the Partnership entered into a pipeline connection agreement with Tesoro High Plains Pipeline Company (“Tesoro High Plains”) whereby Tesoro High Plains would design, engineer, construct and place in service improvements on its pipeline system that will expand its capacity to ship crude oil from points in Dunn and McKenzie Counties, North Dakota to Ramberg Station/Beaver Lodge destination point in Williams County, North Dakota. In connection with this agreement, the Partnership is committed to a minimum take-or-pay throughput commitment of approximately $36.4 million over a seven–year period beginning after the commissioning of the pipeline, which occurred in January of 2015. At December 31, 2015, the remaining commitment on the take-or-pay commitment, including a quarterly take-or-pay of $1.3 million, was approximately $31.2 million.

In April 2014, the Partnership entered into a pipeline connection agreement with Tesoro whereby Tesoro would build, own and operate a four‑mile pipeline lateral from its existing block gate valve in Mercer Country, North Dakota to the Partnership’s Beulah Rail Facility near Beulah, North Dakota. In connection with this agreement, the Partnership is committed to a minimum take-or-pay throughput commitment of approximately $8.7 million over a five‑year period beginning after the commissioning of the pipeline, which occurred in November 2014. At December 31, 2015, the remaining commitment on the take-or-pay commitment was approximately $8.1 million.

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 five–year period beginning after the commissioning of the pipeline, which occurred in August of 2013. At December 31, 2015, the remaining commitment on the take‑or‑pay commitment was $0.

In February 2013, the Partnership assumed natural gas transportation and reservation agreements, which have various expiration dates, with Northwest Natural Gas Company (“NWNatural Gas”) and the Northwest Pipeline system (“NWPipeline”) whereby NWNatural and NWPipeline provide the Partnership with the transportation and reservation of firm natural gas delivered to the Partnership’s Oregon facility. At December31, 2015, the remaining commitment on the transportation and reservation agreements was approximately $14.3million.

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.

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Partners' Equity and Cash Distributions

12 Months Ended

Dec. 31, 2015

Partners' Equity and Cash Distribution

Partners' Equity and Cash Distributions

Note 14. Partners’ Equity, Allocations and Cash Distributions

Partners’ Equity

Partners’ equity at December 31, 2015 consisted of 33,995,563common units issued, including 7,434,775 common units held by affiliates of the General Partner, including directors and executive officers, collectively representing a 99.33% limited partner interest in the Partnership, and 230,303 general partner units representing a 0.67% general partner interest in the Partnership.

The following table presents the changes in the Partnership’s outstanding units:

	Limited Partner Units	General Partner Equivalent Units	Total
Balance at December 31, 2013	27,430,563	230,303	27,660,866
Public offering of common units (see Note 15)	3,565,000	—	3,565,000
Balance at December 31, 2014	30,995,563	230,303	31,225,866
Public offering of common units (see Note 15)	3,000,000	—	3,000,000
Balance at December 31, 2015	33,995,563	230,303	34,225,866

Partners’ equity at December 31, 2015 and 2014 excluded common units outstanding of 403,922 and 390,602, respectively, held pursuant to the Repurchase Program and for future satisfaction of the General Partner’s Obligations (defined herein). See Note 12, “Long‑Term Incentive Plan—Repurchase Program.”

Common Units

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

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 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.

Cash Distributions

The Partnership intends 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. 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. The indentures governing the Partnership’s outstanding senior notes also limit the Partnership’s ability to make distributions to its unitholders in certain circumstances.

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: 99.33% to the common unitholders, pro rata, and 0.67% 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
	Total Quarterly Distribution	Interest in Distributions
	Target Amount	Unitholders		General Partner
First Target Distribution	upto $0.4625	99.33	%	0.67	%
Second Target Distribution	above $0.4625 up to $0.5375	86.33	%	13.67	%
Third Target Distribution	above $0.5375 up to $0.6625	76.33	%	23.67	%
Thereafter	above $0.6625	51.33	%	48.67	%

The Partnership paid the following cash distributions during 2015, 2014 and 2013 (in thousands, except per unit data):

	Earned for the	Per Unit
Cash Distribution	Quarter	Cash		Common		General		Incentive		Total Cash
Payment Date	Ended	Distribution		Units		Partner		Distribution		Distribution
2013
02/14/13 (1)(2)	12/31/12	$	0.5700	$	15,636	$	131	$	579	$	16,346
05/15/13 (1)(2)	03/31/13		0.5825		15,979		134		683		16,796
08/14/13 (1)(2)	06/30/13		0.5875		16,116		135		724		16,975
11/14/13 (1)(2)	09/30/13		0.6000		16,459		138		828		17,425
2014
02/14/14 (1)(2)	12/31/13	$	0.6125	$	16,802	$	140	$	932	$	17,874
05/15/14 (1)(2)	03/31/14		0.6250		17,145		143		1,035		18,323
08/14/14 (1)(2)	06/30/14		0.6375		17,487		146		1,139		18,772
11/14/14 (1)(2)	09/30/14		0.6525		17,899		150		1,270		19,319
2015
02/13/15 (3)(4)	12/31/14	$	0.6650	$	20,612	$	154	$	1,591	$	22,357
05/15/15 (3)(4)	03/31/15		0.6800		21,076		157		2,027		23,260
08/14/15 (4)	06/30/15		0.6925		23,543		159		2,618		26,320
11/13/15 (4)	09/30/15		0.6975		23,713		160		2,777		26,650

(1) Prior to the Partnership’s public offering in December 2014 (see Note 15), the limited partner interest was 99.17% and the general partner interest was 0.83%.

(2) This distribution resulted in the Partnership exceeding its second target level distribution for the respective quarter. As a result, the General Partner, as the holder of the IDRs, received an incentive distribution.

(3) Prior to the Partnership’s public offering in June 2015 (see Note 15), the limited partner interest was 99.26% and the general partner interest was 0.74%.

(4) This distribution resulted in the Partnership exceeding its third target level distribution for the respective quarter. As a result, the General Partner, as the holder of the IDRs, received an incentive distribution.

In addition, on January 28, 2016, the board of directors of the General Partner declared a quarterly cash distribution of $0.4625 per unit ($1.85 per unit on an annualized basis) on all of its outstanding common units for the period from October 1, 2015 through December 31, 2015 to the Partnership’s unitholders of record as of the close of business February 10, 2016. On February 16, 2016, the Partnership paid the total cash distribution of approximately $15.8 million.

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Unitholders' Equity

12 Months Ended

Dec. 31, 2015

Unitholders' Equity

Unitholders' Equity

Note 15. Unitholders’ Equity

Equity Offerings

On June 11, 2015, the Partnership entered into an Underwriting Agreement (the “2015 Underwriting Agreement”) relating to the public offering of 3,000,000 common units at a price to the public of $38.12 per common unit. On June 16, 2015, the Partnership completed the offering, and the net proceeds of approximately $109.3 million (after deducting underwriting discounts and estimated expenses) were used to reduce indebtedness outstanding under the Partnership’s revolving credit facility.

On December 5, 2014, the Partnership entered into an Underwriting Agreement (the “2014 Underwriting Agreement”) relating to the public offering of 3,565,000 common units at a price to the public of $40.24 per common unit. On December 10, 2014, the Partnership completed the offering, and the net proceeds of approximately $137.8 million (after deducting underwriting discounts and estimated expenses) were used to reduce indebtedness outstanding under the Partnership’s revolving credit facility.

At-the-Market Offering Program

On May 19, 2015, the Partnership entered into an equity distribution agreement pursuant to which the Partnership may sell from time to time through its sales agents, the Partnership’s common units having an aggregate offering price of up to $50.0 million. Sales of the common units, if any, will be made by any method permitted by law deemed to be an “at-the-market” offering, including ordinary brokers’ transactions through the facilities of the New York Stock Exchange, to or through a market maker, or directly on or through an electronic communication network, a “dark pool” or any similar market venue, at market prices, in block transactions, or as otherwise agreed upon by the Partnership and one or more of its sales agents.

The Partnership may also sell common units to one or more of its sales agents as principal for its own account at a price to be agreed upon at the time of sale. Any sale of common units to a sales agent as principal would be pursuant to the terms of a separate agreement between the Partnership and such sales agent.

The Partnership intends to use the net proceeds from any sales pursuant to the at-the-market offering program, after deducting the sales agents’ commissions and the Partnership’s offering expenses, for general partnership purposes, which may include, among other things, repayment of indebtedness, acquisitions and capital expenditures.

The sales agents and/or affiliates of each of the sales agents have, from time to time, performed, and may in the future perform, various financial advisory and commercial and investment banking services for the Partnership and its affiliates, for which they have received and in the future will receive customary compensation and expense reimbursement. Affiliates of the sales agents are lenders under the Partnership’s credit facility and, accordingly, may receive a portion of the net proceeds from this offering if and to the extent any proceeds are used to reduce outstanding borrowings under the Partnership’s credit facility.

As of December 31, 2015, no common units were sold by the Partnership pursuant to the at-the-market offering program.

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Related Party Transactions

12 Months Ended

Dec. 31, 2015

Related Party Transactions

Related Party Transactions

Note 16. Related‑Party Transactions

The Partnership was a party to an exclusive Second Amended and Restated Terminal Storage Rental and Throughput Agreement, as amended (the “Terminal Storage Rental and Throughput Agreement”), with GPC, an affiliate of the Partnership that is 100% owned by members of the Slifka family, with respect to the Revere Terminal in Revere, Massachusetts. On January 14, 2015, the Partnership acquired the Revere Terminal from GPC and related entities, and the Terminal Storage Rental and Throughput Agreement was terminated (see Note 3). Prior to the acquisition, the agreement was accounted for as an operating lease. The expenses under this agreement totaled $0.8 million,  $9.2 million and $9.1 million for the years ended December31, 2015, 2014 and 2013, respectively. These expenses include annual consumer price index adjustments of approximately $0,  $1.9 million and $1.8 million for the years ended December31, 2015, 2014 and 2013, respectively.

The Partnership was a party to an Amended and Restated Services Agreement with GPC, whereby GPC provided certain terminal operating management services to the Partnership and used certain administrative, accounting and information processing services of the Partnership. The expenses from these services totaled approximately $8,000,  $96,000 and $96,000 for the years ended December 31, 2015, 2014 and 2013, respectively. These charges were recorded in selling, general and administrative expenses in the accompanying consolidated statements of operations.

On March 11, 2015, the Partnership entered into the following amendments and restatements to its shared services agreements: (i) Global Companies entered into an Amended and Restated Services Agreement with AE Holdings Corp. (the “AE Holdings Amended and Restated Services Agreement”), and (ii) certain of the Partnership’s subsidiaries entered into a Second Amended and Restated Services Agreement with GPC (the “GPC Second Amended and Restated Services Agreement”).

Under the AE Holdings Amended and Restated Services Agreement, the Partnership provided AE Holdings with certain tax, accounting, treasury and legal support services for which AE Holdings paid the Partnership an aggregate of $15,000 per year in equal monthly installments until it was voluntarily dissolved effective on July 10, 2015. Under the GPC Second Amended and Restated Services Agreement, GPC no longer provides the Partnership with terminal, environmental and operational support services, but the Partnership continues to provide GPC with certain tax, accounting, treasury, legal, information technology, human resources and financial operations support services for which GPC pays the Partnership a monthly services fee at an agreed amount subject to the approval by the Conflicts Committee of the board of directors of the General Partner. The GPC Second Amended and Restated Services Agreement is for an indefinite term and any party may terminate some or all of the services upon ninety  (90) days’ advanced written notice. As of December 31, 2015, no such notice of termination was given by GPC.

The General Partner employs substantially all of the Partnership’s employees, except for most of 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 $109.0 million, $95.5 million and $79.3 million for the years ended December 31, 2015, 2014 and 2013, respectively. The Partnership 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):

	2015		2014
Receivables from GPC	$	—	$	108
Receivables from the General Partner (1)		2,578		3,795
Total	$	2,578	$	3,903

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

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Segment Reporting

12 Months Ended

Dec. 31, 2015

Segment Reporting

Segment Reporting

Note 17. Segment Reporting

The Partnership engages in the purchasing, selling, storing and logistics of transporting petroleum and related products, including domestic and Canadian crude oil, gasoline and gasoline blendstocks (such as ethanol), distillates (such as home heating oil, diesel and kerosene), residual oil, renewable fuels, natural gas and propane. The Partnership also receives revenue from convenience store sales and gasoline station rental income. 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, GDSO 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 December31, 2015, 2014 and 2013, 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 branded and unbranded gasoline and gasoline blendstocks and diesel to wholesale distributors. The Partnership transports these products by railcars, barges and/or pipelines pursuant to spot or long‑term contracts. The Partnership aggregates crude oil by truck or pipeline in the mid-continent region of the United States and Canada, transports it by train and ships it by barge to refiners on the East and West Coasts. The Partnership sells home heating oil, diesel, kerosene, residual oil and propane to home heating oil and propane retailers and wholesale distributors. Generally, customers use their own vehicles or contract carriers to take delivery of the gasoline and distillates at bulk terminals and inland storage facilities that the Partnership owns or controls or with which it has throughput or exchange arrangements. Additionally, ethanol is shipped primarily by rail and by barge.

In the GDSO reporting segment, gasoline distribution includes sales of branded and unbranded gasoline to gasoline station operators and sub jobbers. Station operations include (i) convenience stores, (ii) rental income from gasoline stations leased to dealers, from commissioned agents and from cobranding arrangements and (iii) sundries (such as car wash sales, lottery and ATM commissions). The results of Warren, acquired in January 2015, and Capitol, acquired in June 2015 (see Note 3), are included in the GDSO segment.

In the Commercial segment, the Partnership 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, bunker fuel and natural gas. In the case of public sector commercial and industrial end user customers, the Partnership sells products primarily either through a competitive bidding process or through contracts of various terms. The Partnership generally arranges for the delivery of the product to the customer’s designated location, and the Partnership responds to publicly-issued requests for product proposals and quotes. The Commercial segment also includes sales of custom blended fuels delivered by barges or from a terminal dock to ships through bunkering activity.

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.

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,
	2015		2014		2013
Wholesale Segment:
Sales
Gasoline and gasoline blendstocks	$	2,714,057	$	7,076,105	$	8,085,225
Crude oil (1)		1,190,560		2,384,018		3,561,428
Other oils and related products (2)		2,006,668		3,436,006		3,559,001
Total	$	5,911,285	$	12,896,129	$	15,205,654
Product margin
Gasoline and gasoline blendstocks	$	66,031	$	71,713	$	43,147
Crude oil (1)		74,182		141,965		92,807
Other oils and related products (2)		67,709		79,376		66,916
Total	$	207,922	$	293,054	$	202,870
Gasoline Distribution and Station Operations Segment (3):
Sales
Gasoline	$	3,289,742	$	3,241,620	$	3,231,925
Station operations (4)		381,194		165,756		146,503
Total	$	3,670,936	$	3,407,376	$	3,378,428
Product margin
Gasoline	$	276,848	$	189,439	$	150,147
Station operations (4)(5)		178,487		93,939		78,833
Total	$	455,335	$	283,378	$	228,980
Commercial Segment:
Sales	$	732,631	$	966,449	$	1,005,526
Product margin	$	29,201	$	29,716	$	28,359
Combined sales and Product margin:
Sales	$	10,314,852	$	17,269,954	$	19,589,608
Product margin (6)	$	692,458	$	606,148	$	460,209
Depreciation allocated to cost of sales		(94,789)		(61,361)		(55,653)
Combined gross profit	$	597,669	$	544,787	$	404,556

(1) Crude oil consists of the Partnership’s crude oil sales and revenue from its logistics activities.

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

(3) The GDSO segment for 2015 includes the results of the January 2015 acquisition of Warren and the June 2015 acquisition of Capitol (see Note 3). As the Warren assets and the Capitol assets were not in place prior to 2015, the above results are not directly comparable to the prior periods.

(4) Station operations primarily consist of convenience store sales and rental income.

(5) For the years ended December 31, 2014 and 2013, station operations includes the reclass of loss (gain) on sale and disposition of assets from product margin to operating expenses to conform to the Partnership’s current presentation.

(6) Product margin is a non-GAAP financial measure used by management and external users of the Partnership’s consolidated financial statements to assess its business. The table above includes a reconciliation of product margin on a combined basis to gross profit, a directly comparable GAAP measure.

Approximately 450million gallons, 450million gallons and 500million gallons of the GDSO segment’s sales were supplied from petroleum products and renewable fuels sourced by the Wholesale segment for the years ended December31, 2015, 2014 and 2013, respectively. Except for natural gas, predominantly all of the Commercial segment’s sales are sourced by the Wholesale segment. These intra-segment sales are not reflected as sales in the Wholesale segment as they are eliminated.

None of the Partnership’s customers accounted for greater than 10% of total sales for year ended December 31, 2015. In the Wholesale segment, the Partnership had one customer, ExxonMobil, whose revenues were approximately $2.9billion (17%) of the Partnership’s total revenues for the year ended December31, 2014 and two significant customers, ExxonMobil and Phillips66, whose revenues were approximately $2.9 billion (15%) and $2.4 billion (12%), respectively, of the Partnership’s total revenues for the year ended December31, 2013.

A reconciliation of the totals reported for the reportable segments to the applicable line items in the consolidated financial statements for the years ended December31 is as follows (in thousands):

	2015		2014		2013
Combined gross profit	$	597,669	$	544,787	$	404,556
Operating costs and expenses not allocated to operating segments:
Selling, general and administrative expenses		177,043		153,961		115,491
Operating expenses		290,307		204,070		185,713
Amortization expense		13,499		18,867		19,216
Loss (gain) on sale and disposition of assets		2,097		2,182		(1,273)
Total operating costs and expenses		482,946		379,080		319,147
Operating income		114,723		165,707		85,409
Interest expense		(73,332)		(47,764)		(43,537)
Income tax benefit (expense)		1,873		(963)		(819)
Net income		43,264		116,980		41,053
Net loss (income) attributable to noncontrolling interest		299		(2,271)		1,562
Net income attributable to Global Partners LP	$	43,563	$	114,709	$	42,615

The Partnership’s foreign assets and foreign sales were immaterial as of and for the years ended December31, 2015 and 2014. In 2013, the Partnership’s foreign assets were immaterial and there were no foreign sales.

Segment Assets

The Partnership acquired retail gasoline stations from Capitol in June 2015 and Warren in January 2015 which were allocated to the GDSO segment. The Partnership acquired the Revere Terminal in January 2015 which was allocated to the Wholesale segment.

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.

The table below presents total assets by reportable segment at December31, (in thousands):

		Wholesale		Commercial		GDSO		Unallocated		Total
December 31, 2015	$	774,352	$	3,224	$	1,392,397	$	493,702	$	2,663,675
December 31, 2014	$	807,708	$	3,827	$	622,860	$	596,422	$	2,030,817

The increase in total assets allocated to GDSO at December 31, 2015 compared to December31, 2014 is due to the January 2015 acquisition of Warren and the June 2015 acquisition of Capitol (see Note 3).

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Fair Value Measurements

12 Months Ended

Dec. 31, 2015

Fair Value Measurements

Fair Value Measurements

Note 18. Fair Value Measurements

Recurring Fair Value Measures

Assets and liabilities are classified in the entirety based on the lowest level of input that is significant to the fair value measurement. The Partnership’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value assets and liabilities and their placement within the fair value hierarchy levels. The following tables present, by level within the fair value hierarchy, the Partnership’s financial assets and liabilities that were measured at fair value on a recurring basis as of December31, 2015 and 2014 (in thousands):

	Fair Value at December 31, 2015
							Cash Collateral
	Level 1		Level 2		Level 3		Netting		Total
Assets:
Forward derivative contracts (1)	$	—	$	62,382	$	3,717	$	—	$	66,099
Foreign currency derivatives		—		10		—		—		10
Interest rate cap		—		—		—		—		—
Exchange-traded/cleared derivative instruments (2)		95,367		—		—		(64,040)		31,327
Pension plan		16,886		—		—		—		16,886
Total assets	$	112,253	$	62,392	$	3,717	$	(64,040)	$	114,322
Liabilities:
Forward derivative contracts (1)	$	—	$	(27,602)	$	(3,653)	$	—	$	(31,255)
Swap agreements and options		—		(656)		—		—		(656)
Interest rate swaps		—		(3,343)		—		—		(3,343)
Total liabilities	$	—	$	(31,601)	$	(3,653)	$	—	$	(35,254)

	Fair Value at December 31, 2014
							Cash Collateral
	Level 1		Level 2		Level 3		Netting		Total
Assets:
Forward derivative contracts (1)	$	—	$	81,421	$	2,405	$	—	$	83,826
Foreign currency derivatives		—		9		—		—		9
Interest rate cap		—		17		—		—		17
Exchange-traded/cleared derivative instruments (2)		121,490		—		—		(104,292)		17,198
Pension plan		18,023		—		—		—		18,023
Total assets	$	139,513	$	81,447	$	2,405	$	(104,292)	$	119,073
Liabilities:
Forward derivative contracts (1)	$	—	$	(28,500)	$	(27,928)	$	—	$	(56,428)
Swap agreements and options		—		(2,079)		—		—		(2,079)
Interest rate swaps		—		(6,696)		—		—		(6,696)
Total liabilities	$	—	$	(37,275)	$	(27,928)	$	—	$	(65,203)

(1) Forward derivative contracts include the Partnership’s petroleum and ethanol physical and financial forwards and OTC swaps

(2) Amount includes the effect of cash balances on deposit with clearing brokers.

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 facility approximates fair value due to the variable rate nature of these financial instruments.

The carrying value of the inventory qualifying for fair value hedge accounting approximates fair value due to adjustments for changes in fair value of the hedged item. The fair values of the derivatives used by the Partnership are disclosed in Note4.

The determination of the fair values above incorporates factors including not only the credit standing of the counterparties involved, but also the impact of the Partnership’s nonperformance risks on its liabilities.

The values of the Level1 exchange-traded/cleared derivative instruments and pension plan assets were determined using quoted prices in active markets for identical assets. Specifically, the fair values of the Level1 exchange-traded/cleared derivative instruments were based on quoted process obtained from the NYMEX, CME and ICE. The fair values of the Partnership’s Level1 pension plan assets were based on quoted prices for identical assets which primarily consisted of fixed income securities, equity securities and cash and cash equivalents.

The values of the Level2 derivative contracts were calculated using expected cash flow models and market approaches based on observable market inputs, including published and quoted commodity pricing data, which is verified against other available market data. Specifically, the fair values of the Level2 derivative commodity contracts were derived from published and quoted NYMEX, CME, ICE, New York Harbor and third-party pricing information for the underlying instruments using market approaches. The fair value of the Level2 interest rate instruments were derived from the implied forward LIBOR yield curve for the sale period as the future interest rate swap and interest rate cap settlements using expected cash flow models. The fair value of the Level2 foreign currency derivatives were derived from the implied forward currency curve for the Canadian and U.S. Dollar. The Partnership has not changed its valuation techniques or Level2 inputs during the years ended December31, 2015 and 2014.

The carrying values and fair values of the Partnership’s 6.25% Notes and 7.00% Notes, estimated by observing market trading prices of the 6.25% Notes and 7.00% Notes, respectively, were as follows (in thousands):

	December 31, 2015					December 31, 2014
	Carrying			Fair		Carrying		Fair
	Value			Value		Value		Value
6.25% Notes		$	375,000	$	307,500	$	375,000	$	358,594
7.00% Notes		$	300,000	$	249,000	$	—	$	—

Level 3 Information

The values of the Level3 derivative contracts were calculated using market approaches based on a combination of observable and unobservable market inputs, including published and quoted NYMEX, CME, ICE, New York Harbor and third-party pricing information for a component of the underlying instruments as well as internally developed assumptions where there is little, if any, published or quoted prices or market activity. The unobservable inputs used in the measurement of the Level3 derivative contracts include estimates for location basis, transportation and throughput costs net of an estimated margin for current market participants. The estimates for these inputs for crude oil were $4.00 to $13.55 per barrel and $11.00 to $18.00 per barrel for the years ended December31, 2015 and 2014, respectively. The estimates for these inputs for propane were $2.10 to $9.66per barrel for the year ended December31, 2015. Gains and losses recognized in earnings (or changes in net assets) are disclosed in Note4.

Sensitivity of the fair value measurement to changes in the significant unobservable inputs is as follows:

Significant			ImpactonFairValue
Unobservable Input	Position	ChangetoInput	Measurement
Location basis	Long	Increase(decrease)	Gain (loss)
Location basis	Short	Increase(decrease)	Loss (gain)
Transportation	Long	Increase(decrease)	Gain (loss)
Transportation	Short	Increase(decrease)	Loss (gain)
Throughput costs	Long	Increase(decrease)	Gain (loss)
Throughput costs	Short	Increase(decrease)	Loss(gain)

The following table presents a reconciliation of changes in fair value of the Partnership’s derivative contracts classified as Level3 in the fair value hierarchy at December31 (in thousands):

Fair value at December 31, 2014	$	(25,523)
Transfers into Level 3 (1)(2)		516
Realized and unrealized gains (losses) recorded in cost of sales		25,071
Fair value at December 31, 2015	$	64

(1) Transfers from Level 2 to Level 3 were due to certain market inputs associated with propane that were previously considered observable that became unobservable during the year ended December 31, 2015, given increased volatility in the market for this product.

(2) The Partnership’s policy is to recognize transfers between levels with the fair value hierarchy as of the beginning of the reporting period.

Non-Recurring Fair Value Measures

Certain nonfinancial assets and liabilities are measured at fair value on a non-recurring basis and are subject to fair value adjustments in certain circumstances, such as acquired assets and liabilities or losses related to firm non-cancellable purchase commitments. 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 year ended December 31, 2015.

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Changes in Accumulated Other Comprehensive Loss

12 Months Ended

Dec. 31, 2015

Changes in Accumulated Other Comprehensive (Income) Loss

Changes in Accumulated Other Comprehensive Loss

Note 19. Changes in Accumulated Other Comprehensive Loss

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

	Pension Plan		Derivatives		Total
Balance at December 31, 2013	$	(454)	$	(10,856)	$	(11,310)
Other comprehensive (loss) income before reclassifications of gain (loss)		(4,660)		3,151		(1,509)
Amount of gain (loss) reclassified from accumulated other comprehensive (loss) income		(433)		—		(433)
Total comprehensive (loss) income		(5,093)		3,151		(1,942)
Balance at December 31, 2014		(5,547)		(7,705)		(13,252)
Other comprehensive income before reclassifications of gain (loss)		1,192		4,047		5,239
Amount of gain (loss) reclassified from accumulated other comprehensive (loss) income		(81)		—		(81)
Total comprehensive income		1,111		4,047		5,158
Balance at December 31, 2015	$	(4,436)	$	(3,658)	$	(8,094)

Amounts are presented prior to the income tax effect on other comprehensive income. Given the Partnership’s master limited partnership status, the effective tax rate is immaterial.

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Legal Proceedings

12 Months Ended

Dec. 31, 2015

Legal Proceedings

Legal Proceedings

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

In February 2016, the Partnership received a request for information from the EPA seeking certain information regarding the Albany Terminal in order to assess its compliance with the Clean Air Act (the “CAA”). The information requested generally relates to crude oil received by, stored at and shipped from the Partnership’s petroleum product transloading facility in Albany, New York (the “Albany Terminal”), including its composition, control devices for emissions and various permitting-related considerations. The Albany Terminal is a 63-acre licensed, permitted and operational stationary bulk petroleum storage and transfer terminal that currently consists of petroleum product storage tanks, along with truck, rail and marine loading facilities, for the storage, blending and distribution of various petroleum and related products, including gasoline, ethanol, distillates, heating and crude oils. The Partnership intends to cooperate fully with the agency and believes the responsive information will demonstrate that the Partnership’s operations at the Albany Terminal are in compliance with all pertinent requirements.

By letter dated October 5, 2015, the Partnership received a notice of intent to sue (the “October NOI”), which supersedes and replaces a prior notice of intent to sue that the Partnership received on September 1, 2015 (the “September NOI”) from Earthjustice, an environmental advocacy organization on behalf of the County of Albany, New York, a public housing development owned and operated by the Albany Housing Authority and certain environmental organizations, related to alleged violations of the CAA at the Albany Terminal, particularly with respect to crude oil operations at the Albany Terminal. The October NOI revises the superseded and replaced September NOI to add two additional environmental advocacy organizations and to revise the relief sought and the description of the alleged CAA violations.

On February 3, 2016, Earthjustice and the other entities identified in the October NOI filed suit against the Partnership in federal court in Albany under the citizen suit provisions of the CAA. In summary, this lawsuit alleges that the Partnership’s operations at the Albany Terminal are in violation of the CAA. The plaintiffs seek, among other things, relief that would compel the Partnership both to apply for what they contend is the applicable permit under the CAA, and to install additional pollution controls. In addition, the plaintiffs seek to prohibit the Albany Terminal from receiving, storing, handling, and marine loading certain types of Bakken crude oil and to require payment of a civil penalty of $37,500 for each day the Partnership as operated the Albany Terminal in violation of the CAA. The Partnership believes that it has meritorious defenses against all allegations and will vigorously contest this lawsuit.

On May 29, 2015 and in connection with a commercial dispute with Tethys Trading Company LLC (“Tethys”), the Partnership received a notice from Tethys alleging a default under, and purporting to terminate, the Partnership’s contract with Tethys for crude oil services at the Partnership’s Oregon facility. However, the Partnership does not believe Tethys had the right to terminate the contract, and the Partnership will take appropriate action to enforce its rights under the agreement. The Partnership had expected to receive fees from this contract of approximately $13.2 million for the period July 1, 2015 through December 31, 2015 and approximately $105.2 million in the aggregate for the remaining four years of the contract.

On March26, 2015, the Partnership received a Notice of Non-Compliance (“NON”) from the Massachusetts Department of Environmental Protection (“DEP”) with respect to the Revere Terminal, alleging certain violations of the National Pollutant Discharge Elimination System Permit (“NPDES Permit”) related to storm water discharges. The NON requires the Partnership to submit a plan to remedy the reported violations of the NPDES Permit. The Partnership has responded to the NON with a plan and is implementing modifications to the storm water management system at the Revere Terminal. The Partnership has determined that compliance with the NON and implementation of the plan will have no material impact on its operations.

The Partnership has a dispute with Lansing Ethanol Services, LLC (“Lansing”) for damages in excess of $12.0million. The dispute involves Lansing’s failure to transfer Renewable Fuel Identification Numbers to the Partnership in connection with certain agreements for the purchase and sale of ethanol. The parties have agreed to arbitrate under the rules of the American Arbitration Association. The Partnership filed for arbitration on March24, 2015 and anticipates arbitration to commence during the first quarter ending March31, 2016. The Partnership believes it has meritorious positions and intends to vigorously pursue a favorable result in connection with this dispute.

On July 2, 2014, a lawsuit was filed by the Northwest Environmental Defense Center and other environmental non-government organizations (the “Plaintiffs”) against the Partnership and Cascade Kelly alleging violations of the CAA. The suit, filed in the United States District Court for the district of Oregon, alleged that Cascade Kelly was operating without the proper permit under the applicable rules. The lawsuit sought penalties, injunctive relief and reimbursement of attorneys’ fees. A trial was held during the fourth quarter of 2015. On December 30, 2015, the Court issued a judgment in the Partnership’s favor and dismissed the case with prejudice. The time for requesting an appeal has passed and the Plaintiffs did not appeal. Accordingly, the case is closed.

On May 16, 2014, the Partnership received a subpoena from the SEC requesting information for relevant time periods primarily relating to the Partnership’s accounting for RINs and the restatements of its consolidated financial statements as of and for the quarters ended March31, 2013, June30, 2013 and September30, 2013. The Partnership intends to continue to cooperate fully with, and has produced responsive materials to, the SEC.

The Partnership received letters from the EPA dated November 2, 2011 and March 29, 2012, containing requirements and testing orders (collectively, the “Requests for Information”) for information under the CAA. The Requests for Information were part of an EPA investigation to determine whether the Partnership has violated sections of the CAA at certain of its terminal locations in New England with respect to residual oil and asphalt. On June6, 2014, a Notice of Violation (“NOV”) was received from the EPA, alleging certain violations of its Air Emissions License issued by the Maine Department of Environmental Protection, based upon the test results at the South Portland, Maine terminal. The Partnership met with and provided additional information to the EPA with respect to the alleged violations. On April 7, 2015, the EPA issued a Supplemental Notice of Violation (the “Supplemental NOV”) modifying the allegations of violations of the terminal’s Air Emissions License. The Partnership has responded to the Supplemental NOV and is engaged in further negotiations with the EPA. A tolling agreement was executed with the United States on December 1, 2015, and negotiations are continuing in the first quarter of 2016. The Partnership does not believe that a material violation has occurred, and it contests the allegations presented in the NOV and Supplemental NOV. The Partnership does not believe any adverse determination in connection with the NOV would have a material impact on its operations.

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Quarterly Financial Data (Unaudited)

12 Months Ended

Dec. 31, 2015

Quarterly Financial Data (Unaudited)

Quarterly Financial Data (Unaudited)

Note 21. 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, 2015
Sales	$	2,979,116	$	2,680,088	$	2,486,203	$	2,169,445	$	10,314,852
Gross profit (1)	$	168,558	$	144,188	$	152,299	$	132,624	$	597,669
Net income (loss) (1)(2)(3)	$	30,409	$	7,614	$	8,146	$	(2,905)	$	43,264
Net income (loss) attributable to Global Partners LP	$	30,415	$	7,218	$	8,212	$	(2,282)	$	43,563
Limited partners’ interest in net income (loss)	$	28,236	$	4,547	$	5,380	$	(2,267)	$	35,896
Basic net income (loss) per limited partner unit	$	0.92	$	0.15	$	0.16	$	(0.70)	$	1.12
Diluted net income (loss) per limited partner unit	$	0.92	$	0.15	$	0.16	$	(0.70)	$	1.11
Cash distributions per limited partner unit (5)	$	0.6650	$	0.6800	$	0.6925	$	0.6975	$	2.74

	First		Second		Third		Fourth		Total
Year ended December 31, 2014
Sales	$	5,116,928	$	4,569,620	$	4,050,458	$	3,532,948	$	17,269,954
Gross profit (4)	$	159,024	$	87,685	$	155,435	$	142,643	$	544,787
Net income (loss) (2)(4)	$	57,154	$	(12,278)	$	43,622	$	28,482	$	116,980
Net income (loss) attributable to Global Partners LP	$	57,010	$	(12,719)	$	42,508	$	27,910	$	114,709
Limited partners’ interest in net (loss) income	$	55,502	$	(13,752)	$	40,885	$	26,093	$	108,728
Basic net income (loss) per limited partner unit	$	2.04	$	(0.50)	$	1.50	$	0.93	$	3.97
Diluted net income (loss) per limited partner unit	$	2.03	$	(0.50)	$	1.50	$	0.93	$	3.95
Cash distributions per limited partner unit (5)	$	0.6125	$	0.6250	$	0.6375	$	0.6525	$	2.53

(1) Includes a $5.0 million charge related to a customer dispute in the first quarter of 2015.

(2) Includes the following charges in connection with the acquisition of Warren: (i)acquisition costs of $4.4 million and $1.0 million in the first and second quarters of 2015, respectively, and $1.7 million in the fourth quarter of 2014; and (ii) a restructuring charge of $2.3 million in the first quarter of 2015.

(3) Includes acquisition costs in connection with the acquisition of Capitol of $3.1 million and $0.1 million in the second and third quarters of 2015, respectively.

(4) Includes the reclass of loss on sale and disposition of assets within GDSO’s station operations product margin to operating expenses of $0.7million, $0.4million and $1.1million in the first, second and fourth quarters of 2014, respectively, to conform to the Partnership’s current presentation.

(5) Cash distributions declared in one calendar quarter are paid in the following calendar quarter.

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Subsequent Event

12 Months Ended

Dec. 31, 2015

Subsequent Event Abstract

Subsequent Event

Note 22. Subsequent Events

The Partnership has identified certain non-strategic owned or leasehold assets of the GDSO segment which could result in the sale of more than 100 sites. As the Partnership is still in the preliminary stages of evaluating its portfolio of assets, any assets identified for disposition have not met the criteria to be presented as held for sale as of December 31, 2015.

On February 16, 2016, the Partnership paid a cash distribution of approximately $15.8 million to its unitholders of record as of the close of business on February 10, 2016.

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Supplemental Guarantor Condensed Consolidating Financial Statements

12 Months Ended

Dec. 31, 2015

Supplemental Guarantor Condensed Consolidating Financial Statements

Supplemental Guarantor Condensed Consolidating Financial Statements

Note 23. Supplemental Guarantor Condensed Consolidating Financial Statements

The Partnership’s wholly-owned subsidiaries, other than GLP Finance, are guarantors of senior notes issued by the Partnership and GLP Finance. As such, the Partnership is subject to the requirements of Rule 3-10 of Regulation S-X of the SEC regarding financial statements of guarantors and issuers of registered guaranteed securities. The Partnership presents condensed consolidating financial information for its subsidiaries within the notes to consolidated financial statements in accordance with the criteria established for parent companies in the SEC’s Regulation S-X, Rule 3-10(d). The following condensed consolidating financial information presents the Condensed Consolidating Balance Sheets as of December 31, 2015 and 2014, the Condensed Consolidating Statements of Operations for the years ended December 31, 2015, 2014 and 2013 and the Condensed Consolidating Statements of Cash Flows for the years ended December 31, 2015, 2014 and 2013 of the Partnership’s 100% owned guarantor subsidiaries, the non-guarantor subsidiary and the eliminations necessary to arrive at the information for the Partnership on a consolidated basis. The principal elimination entries eliminate investments in subsidiaries and intercompany balances and transactions.

Condensed Consolidating Balance Sheet

December 31, 2015

(In thousands)

		Issuer	Non-
	Guarantor		Guarantor
	Subsidiaries		Subsidiary		Eliminations		Consolidated
Assets
Current assets:
Cash and cash equivalents	$	—	$	4,690	$	(3,574)	$	1,116
Accounts receivable, net		311,079		275		—		311,354
Accounts receivable - affiliates		2,745		746		(913)		2,578
Inventories		388,952		—		—		388,952
Brokerage margin deposits		31,327		—		—		31,327
Derivative assets		66,099		—		—		66,099
Prepaid expenses and other current assets		65,376		233		—		65,609
Total current assets		865,578		5,944		(4,487)		867,035
Property and equipment, net		1,203,251		39,432		—		1,242,683
Intangible assets, net		75,694		—		—		75,694
Goodwill		349,306		86,063		—		435,369
Other assets		42,894		—		—		42,894
Total assets	$	2,536,723	$	131,439	$	(4,487)	$	2,663,675
Liabilities and partners' equity
Current liabilities:
Cash overdraft	$	3,574	$	—	$	(3,574)	$	—
Accounts payable		303,242		539		—		303,781
Accounts payable - affiliates		746		167		(913)		—
Working capital revolving credit facility - current portion		98,100		—		—		98,100
Environmental liabilities - current portion		5,350		—		—		5,350
Trustee taxes payable		95,264		—		—		95,264
Accrued expenses and other current liabilities		59,742		586		—		60,328
Derivative liabilities		31,911		—		—		31,911
Total current liabilities		597,929		1,292		(4,487)		594,734
Working capital revolving credit facility - less current portion		150,000		—		—		150,000
Revolving credit facility		269,000		—		—		269,000
Senior notes		656,564		—		—		656,564
Environmental liabilities - less current portion		67,883		—		—		67,883
Financing obligation		89,790		—		—		89,790
Deferred tax liabilities		84,836		—		—		84,836
Other long-term liabilities		56,884		—		—		56,884
Total liabilities		1,972,886		1,292		(4,487)		1,969,691
Partners' equity
Global Partners LP equity		563,837		83,952		—		647,789
Noncontrolling interest		—		46,195		—		46,195
Total partners' equity		563,837		130,147		—		693,984
Total liabilities and partners' equity	$	2,536,723	$	131,439	$	(4,487)	$	2,663,675

Condensed Consolidating Balance Sheet

December 31, 2014

(In thousands)

	Issuer		Non-
	Guarantor		Guarantor
	Subsidiaries		Subsidiary		Eliminations		Consolidated
Assets
Current assets:
Cash and cash equivalents	$	2,560	$	2,678	$	—	$	5,238
Accounts receivable, net		456,423		1,307		—		457,730
Accounts receivable - affiliates		4,584		820		(1,501)		3,903
Inventories		336,813		—		—		336,813
Brokerage margin deposits		17,198		—		—		17,198
Derivative assets		83,826		—		—		83,826
Prepaid expenses and other current assets		53,681		634		—		54,315
Total current assets		955,085		5,439		(1,501)		959,023
Property and equipment, net		778,385		46,666		—		825,051
Intangible assets, net		45,870		3,032		—		48,902
Goodwill		68,015		86,063		—		154,078
Other assets		43,763		—		—		43,763
Total assets	$	1,891,118	$	141,200	$	(1,501)	$	2,030,817
Liabilities and partners' equity
Current liabilities:
Accounts payable	$	455,629	$	990	$	—	$	456,619
Accounts payable - affiliates		820		681		(1,501)		—
Line of credit		—		700		—		700
Environmental liabilities - current portion		3,101		—		—		3,101
Trustee taxes payable		105,744		—		—		105,744
Accrued expenses and other current liabilities		81,686		1,134		—		82,820
Derivative liabilities		58,507		—		—		58,507
Total current liabilities		705,487		3,505		(1,501)		707,491
Working capital revolving credit facility - less current portion		100,000		—		—		100,000
Revolving credit facility		133,800		—		—		133,800
Senior notes		360,096		—		—		360,096
Environmental liabilities - less current portion		34,462		—		—		34,462
Deferred tax liabilities		12,958		—		—		12,958
Other long-term liabilities		45,854		—		—		45,854
Total liabilities		1,392,657		3,505		(1,501)		1,394,661
Partners' equity
Global Partners LP equity		498,461		88,481		—		586,942
Noncontrolling interest		—		49,214		—		49,214
Total partners' equity		498,461		137,695		—		636,156
Total liabilities and partners' equity	$	1,891,118	$	141,200	$	(1,501)	$	2,030,817

Condensed Consolidating Statement of Operations

For the Year Ended December 31, 2015

(In thousands)

			Non-
	Guarantor		Guarantor
	Subsidiaries		Subsidiary		Eliminations		Consolidated
Sales	$	10,306,493	$	23,549	$	(15,190)	$	10,314,852
Cost of sales		9,722,340		10,033		(15,190)		9,717,183
Gross profit		584,153		13,516		—		597,669
Costs and operating expenses:
Selling, general and administrative expenses		174,925		2,118		—		177,043
Operating expenses		281,201		9,106		—		290,307
Amortization expense		10,467		3,032		—		13,499
Loss on sale and disposition of assets		2,097		—		—		2,097
Total costs and operating expenses		468,690		14,256		—		482,946
Operating income (loss)		115,463		(740)		—		114,723
Interest expense		(73,324)		(8)		—		(73,332)
Income (loss) before income tax expense		42,139		(748)		—		41,391
Income tax expense		1,873		—		—		1,873
Net income (loss)		44,012		(748)		—		43,264
Net loss attributable to noncontrolling interest		—		299		—		299
Net income (loss) attributable to Global Partners LP		44,012		(449)		—		43,563
Less: General partner's interest in net income, including incentive distribution rights		7,667		—		—		7,667
Limited partners' interest in net income (loss)	$	36,345	$	(449)	$	—	$	35,896

Condensed Consolidating Statement of Operations

For the Year Ended December 31, 2014

(In thousands)

			Non-
	Guarantor		Guarantor
	Subsidiaries		Subsidiary		Eliminations		Consolidated
Sales	$	17,256,583	$	39,347	$	(25,976)	$	17,269,954
Cost of sales		16,743,163		7,980		(25,976)		16,725,167
Gross profit		513,420		31,367		—		544,787
Costs and operating expenses:
Selling, general and administrative expenses		150,964		2,997		—		153,961
Operating expenses		192,512		11,558		—		204,070
Amortization expense		7,846		11,021		—		18,867
Loss on sale and disposition of assets		2,182		—		—		2,182
Total costs and operating expenses		353,504		25,576		—		379,080
Operating income (loss)		159,916		5,791		—		165,707
Interest expense		(47,651)		(113)		—		(47,764)
Income (loss) before income tax expense		112,265		5,678		—		117,943
Income tax expense		(963)		—		—		(963)
Net income		111,302		5,678		—		116,980
Net (income) loss attributable to noncontrolling interest		—		(2,271)		—		(2,271)
Net income attributable to Global Partners LP		111,302		3,407		—		114,709
Less: General partner's interest in net income, including incentive distribution rights		5,981		—		—		5,981
Limited partners' interest in net income	$	105,321	$	3,407	$	—	$	108,728

Condensed Consolidating Statement of Operations

For the Year Ended December 31, 2013

(In thousands)

			Non-
	Guarantor		Guarantor
	Subsidiaries		Subsidiaries		Eliminations		Consolidated
Sales	$	19,575,042	$	28,948	$	(14,382)	$	19,589,608
Cost of sales		19,194,385		5,049		(14,382)		19,185,052
Gross profit		380,657		23,899		—		404,556
Costs and operating expenses:
Selling, general and administrative expenses		110,228		5,263		—		115,491
Operating expenses		175,284		10,429		—		185,713
Amortization expense		7,106		12,110		—		19,216
Gain on sale and disposition of assets		(1,273)		—		—		(1,273)
Total costs and operating expenses		291,345		27,802		—		319,147
Operating income (loss)		89,312		(3,903)		—		85,409
Interest expense		(43,536)		(1)		—		(43,537)
Income (loss) before income tax expense		45,776		(3,904)		—		41,872
Income tax expense		(819)		—		—		(819)
Net income (loss)		44,957		(3,904)		—		41,053
Net loss attributable to noncontrolling interest		—		1,562		—		1,562
Net income (loss) attributable to Global Partners LP		44,957		(2,342)		—		42,615
Less: General partner's interest in net income, including incentive distribution rights		3,521		—		—		3,521
Limited partners' interest in net income	$	41,436	$	(2,342)	$	—	$	39,094

Condensed Consolidating Statement of Cash Flows

For the Year Ended December 31, 2015

(In thousands)

	(Issuer)		Non-
	Guarantor		Guarantor
	Subsidiaries		Subsidiary		Consolidated
Cash flows from operating activities
Net cash provided by operating activities	$	50,309	$	12,197	$	62,506
Cash flows from investing activities
Acquisitions		(561,170)		—		(561,170)
Capital expenditures		(90,240)		(2,685)		(92,925)
Proceeds from sale of property and equipment		4,331		—		4,331
Net cash used in investing activities		(647,079)		(2,685)		(649,764)
Cash flows from financing activities
Proceeds from issuance of common units, net		109,305		—		109,305
Borrowings from working capital revolving credit facility		148,100		—		148,100
Borrowings from revolving credit facility		135,200		—		135,200
Proceeds from senior notes, net of discount		295,338		—		295,338
Payments on line of credit		—		(700)		(700)
Repurchase of common units		(3,892)		—		(3,892)
Noncontrolling interest capital contribution		9,360		(6,800)		2,560
Distribution to noncontrolling interest		(5,280)		—		(5,280)
Distributions to partners		(97,495)		—		(97,495)
Net cash provided by (used in) financing activities		590,636		(7,500)		583,136
Cash and cash equivalents
(Decrease) increase in cash and cash equivalents		(6,134)		2,012		(4,122)
Cash and cash equivalents at beginning of year		2,560		2,678		5,238
Cash and cash equivalents at end of year	$	(3,574)	$	4,690	$	1,116

Condensed Consolidating Statement of Cash Flows

For the Year Ended December 31, 2014

(In thousands)

	(Issuer)		Non-
	Guarantor		Guarantor
	Subsidiaries		Subsidiary		Consolidated
Cash flows from operating activities
Net cash provided by operating activities	$	321,319	$	23,583	$	344,902
Cash flows from investing activities
Capital expenditures		(78,863)		(16,251)		(95,114)
Proceeds from sale of property and equipment		4,021		—		4,021
Net cash used in investing activities		(74,842)		(16,251)		(91,093)
Cash flows from financing activities
Proceeds from public offering, net		137,844		—		137,844
Payments on working capital revolving credit facility		(227,000)		—		(227,000)
Payments on revolving credit facility		(300,900)		—		(300,900)
Payments on line of credit		—		(3,000)		(3,000)
Proceeds from senior notes, net of discount		258,903		—		258,903
Repayment of senior notes		(40,244)		—		(40,244)
Repurchase of common units		(8,632)		—		(8,632)
Noncontrolling interest capital contribution		10,700		(2,500)		8,200
Distribution to noncontrolling interest		(9,200)		—		(9,200)
Distributions to partners		(73,759)		—		(73,759)
Net cash used in financing activities		(252,288)		(5,500)		(257,788)
Cash and cash equivalents
(Decrease) increase in cash and cash equivalents		(5,811)		1,832		(3,979)
Cash and cash equivalents at beginning of year		8,371		846		9,217
Cash and cash equivalents at end of year	$	2,560	$	2,678	$	5,238

Condensed Consolidating Statement of Cash Flows

For the Year Ended December 31, 2013

(In thousands)

	(Issuer)		Non-
	Guarantor		Guarantor
	Subsidiaries		Subsidiary		Consolidated
Cash flows from operating activities
Net cash provided by operating activities	$	240,699	$	14,448	$	255,147
Cash flows from investing activities
Acquisitions		(94,179)		(91,083)		(185,262)
Capital expenditures		(53,484)		(13,648)		(67,132)
Proceeds from sale of property and equipment		9,179		8		9,187
Net cash used in investing activities		(138,484)		(104,723)		(243,207)
Cash flows from financing activities
Payments on working capital revolving credit facility		(97,500)		—		(97,500)
Borrowings from revolving credit facility		12,700		—		12,700
Proceeds from issuance of term loan		115,000		—		115,000
Repayment of term loan		(115,000)		—		(115,000)
Borrowings from line of credit		—		3,700		3,700
Proceeds from senior notes, net of discount		147,900		—		147,900
Repurchase of common units		(4,590)		—		(4,590)
Repurchased units withheld for tax obligations		(2,086)		—		(2,086)
Noncontrolling interest capital contribution		(85,996)		87,421		1,425
Distribution to noncontrolling interest		(2,920)		—		(2,920)
Distributions to partners		(67,329)		—		(67,329)
Net cash used in (provided by) financing activities		(99,821)		91,121		(8,700)
Cash and cash equivalents
Increase in cash and cash equivalents		2,394		846		3,240
Cash and cash equivalents at beginning of year		5,977		—		5,977
Cash and cash equivalents at end of year	$	8,371	$	846	$	9,217

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SCHEDULE II-VALUATION AND QUALIFYING ACCOUNTS

12 Months Ended

Dec. 31, 2015

SCHEDULE II-VALUATION AND QUALIFYING ACCOUNTS

SCHEDULE II-VALUATION AND QUALIFYING ACCOUNTS

SCHEDULE II—VALUATION AND QUALIFYING ACCOUNTS

GLOBAL PARTNERS LP

FOR THE YEARS ENDED DECEMBER 31, 2015, 2014 and 2013

(In thousands)

	Balance at		Charged to								Balance
	Beginning		Costs and						Other		at End
Description	of Period		Expenses		Recoveries		Write Offs		Adjustment		of Period
Year ended December 31,  2015
Allowance for doubtful accounts—accounts receivable	$	4,818	$	1,303	$	42	$	(1,297)	$	1,076	$	5,942
Year ended December 31,  2014
Allowance for doubtful accounts—accounts receivable	$	7,513	$	1,700	$	277	$	(4,672)	$	—	$	4,818
Year ended December 31,  2013
Allowance for doubtful accounts—accounts receivable	$	5,131	$	4,145	$	9	$	(1,772)	$	—	$	7,513

XML

Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2015

Summary of Significant Accounting Policies

Basis of Consolidation and Presentation

Basis of Consolidation and Presentation

On January 7, 2015, the Partnership acquired 100% of the equity interests in Warren, on January 14, 2015, the Partnership acquired the Revere Terminal and on June 1, 2015, the Partnership acquired Capitol. The financial results of Warren and the Revere Terminal for the year ended December 31, 2015 and of Capitol for the seven months ended December 31, 2015 are included in the accompanying statement of operations for the year ended December 31, 2015.

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”). 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 operations for the year ended December 31, 2013.

See Note 3, “Business Combinations,” for additional information on the Partnership’s acquisitions. The accompanying consolidated financial statements as of December 31, 2015 and 2014 and for the years ended December 31, 2015, 2014 and 2013 reflect the accounts of the Partnership. Upon consolidation, all intercompany balances and transactions have been eliminated.

Reclassification

Reclassifications

Certain prior year amounts in the consolidated financial statements have been reclassified to conform to the current year presentation.

Noncontrolling Interest

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 statements 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 statements 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 sheets and statements of operations.

Use of Estimates

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) fair value of derivative instruments, (iii) accruals and contingent liabilities, (iv) allowance for doubtful accounts, (v) Level 3 valuations for crude oil and propane forward purchase and sales contracts, and (vi) assumptions used to evaluate goodwill, property and equipment and intangibles for impairment and environmental and asset retirement obligations provisions and cost of sales accrual. Although the Partnership believes these estimates are reasonable, actual results could differ from these estimates.

Cash and Cash Equivalents

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

Accounts Receivable

The Partnership’s accounts receivable primarily results 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, 2015 and 2014, substantially all of the Partnership’s accounts receivable classified as current assets were within payment terms.

Inventories

Inventories

The Partnership hedges substantially all of its petroleum and ethanol inventory using a variety of instruments, primarily exchange-traded futures contracts. These futures contracts are entered into when inventory is purchased and are either designated as fair value hedges against the inventory on a specific barrel basis for inventories qualifying for fair value hedge accounting or not designated and maintained as economic hedges against certain inventory of the Partnership on a specific barrel basis. Changes in fair value of these futures contracts, as well as the offsetting change in fair value on the hedged inventory, is recognized in earnings as an increase or decrease in cost of sales. All hedged inventory designated in a fair value hedge relationship is valued using the lower of cost, as determined by specific identification, or market, as determined at the product level. All petroleum and ethanol inventory not designated in a fair value hedging relationship is carried at the lower of historical cost, on a first-in, first-out basis, or market.

Convenience store inventory and Renewable Identification Numbers (“RINs”) inventory are carried at the lower of historical cost or market.

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

	2015		2014
Distillates: home heating oil, diesel and kerosene	$	156,411	$	163,679
Gasoline		62,467		82,080
Gasoline blendstocks		32,542		33,760
Crude oil		102,253		20,769
Residual oil		12,895		20,602
Propane and other		1,469		5,123
Renewable identification numbers (RINs)		803		2,057
Convenience store inventory		20,112		8,743
Total	$	388,952	$	336,813

In addition to its own inventory, the Partnership has exchange agreements for petroleum products and ethanol with unrelated third‑party suppliers, whereby it may draw inventory from these other suppliers (see Revenue Recognition) and suppliers may draw inventory from the Partnership. Positive exchange balances are accounted for as accounts receivable and amounted to $3.4 million and $3.9 million at December 31, 2015 and 2014, respectively. Negative exchange balances are accounted for as accounts payable and amounted to $12.1 million and $16.5 million at December 31, 2015 and 2014, respectively. Exchange transactions are valued using current carrying costs.

Property and Equipment

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 related to the Partnership’s terminal assets and gasoline stations is charged to cost of sales and all other depreciation is charged to selling, general and administrative expenses. Depreciation is charged 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:

Gasoline station buildings, improvements and storage tanks	15-25	years
Buildings, docks, terminal facilities and improvements	5-25	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

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

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.

No material impairment charges were required in 2015, 2014 and 2013. However, at December 31, 2015, the Partnership had a $39.4 million remaining net book value of long‑lived assets used at its crude oil transloading terminals in North Dakota. The long‑term recoverability of these assets might be adversely impacted by any prolonged decline in crude oil commodity prices or crude oil differentials. Over the long‑term, if these market conditions remain, this may become an indicator of the potential impairment of these North Dakota assets in the future. The Partnership will monitor the pricing environment and the related impact this may have on the North Dakota operating and cash flows and whether this would constitute an impairment indicator.

The Partnership evaluates its assets for impairment on a quarterly basis.

Goodwill

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. At December 31, 2015, goodwill recorded in the accompanying consolidated balance sheet aggregated $435.4 million, of which $121.7 million relates to the Wholesale segment and $313.7 million relates to the GDSO segment.

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 process of testing goodwill for impairment involves numerous judgments, assumptions and estimates made by management which inherently reflect a high degree of uncertainty. 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. In the quantitative assessment, the fair value of each reporting unit is determined and compared to the book value of the reporting unit. If the fair value of the reporting unit is less than the book value, including goodwill, then the recorded goodwill is impaired to its implied fair value with a charge to operations. The Partnership calculates the fair value of each reporting unit using a combination of discounted cash flows and market comparables.

Key assumptions included in the development of the discounted cash flow value for each reporting unit include:

Future commodity volumes and margins.  The discounted cash flows are based on a five-year forecast with an estimate of terminal value. In general, the reporting units’ fair values are most sensitive to volume and gross margin assumptions. In particular, the Wholesale segment’s cash flows are impacted by the crude oil market, given the Partnership’s 2013 investment in transloading terminals in North Dakota and Oregon. The significant decline in the price of crude oil and tight crude oil differentials negatively impacted the Partnership’s fiscal 2015 results. The Partnership expects low crude oil prices and tight differentials to continue for a period of time, which will negatively impact the Partnership’s 2016 performance with recovery expected in 2017. As a result of these market conditions, there is increased uncertainty and sensitivity relating to the Partnership’s future cash flow projections within its crude oil business on which the Wholesale reporting unit’s goodwill impairment analysis relies. If market conditions, and therefore the Partnership’s performance, are worse than its projections, the Partnership may record impairment charges in the future. Actual results may not be consistent with these judgments, assumptions and estimates, and goodwill impairment charges may be required in future periods. This could have an adverse impact on the Partnership’s financial position and results of operations.

Discount rate commensurate with the risks involved.  The Partnership applies a discount rate to its expected cash flows based on a variety of factors, including market and economic conditions, operational risk, regulatory risk and political risk. A higher discount rate decreases the net present value of cash flows.

Future capital requirements.  The Partnership’s estimates of future capital requirements are based upon a combination of authorized spending and internal forecasts.

On October 1, 2015, the Partnership completed its quantitative assessments for both the Wholesale and GDSO reporting units, and no impairment indicator was identified for either reporting unit. The declining crude oil prices, changes in certain market conditions, and decline in the Partnership’s common unit price, collectively caused the Partnership to reassess its goodwill for impairment as of December31, 2015 for the Wholesale reporting unit. Based on the results of this assessment, the Partnership concluded that step-two of the quantitative assessment was not necessary and no impairment was required. 

The fair values of the Partnership’s reporting units are based on underlying assumptions that represent the Partnership’s best estimates. Many of the factors used in assessing fair value are outside of the control of management. A further sustained decline in commodity prices may cause the Partnership to reassess its long-lived assets and goodwill for impairment, and could result in future non-cash impairment charges as a result of such impairment assessments. If the Partnership is required to perform step-two in the future for the Wholesale reporting unit, up to $121.7million of goodwill assigned to this reporting unit could be written off in the period of such impairment assessment.

During 2014, the Partnership completed step-one quantitative assessments for both the Wholesale and GDSO reporting units and no impairment was identified for either reporting unit. Due to declining oil prices and other market indicators at December 31, 2014, the Partnership updated the assessment of the recovery of goodwill through December 31, 2014 and concluded there was no impairment. During 2013, the Partnership completed a qualitative assessment for the GDSO reporting unit and no impairment was required. During 2013, a quantitative assessment was completed for the Wholesale reporting unit, and no impairment was required.

Environmental and Other Liabilities

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.

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

Asset Retirement Obligations

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 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. The liability for an asset retirement obligation is recognized on a discounted basis in the year in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying cost of the asset. The Partnership had approximately $7.8 million and $3.8 million in total asset retirement obligations at December 31, 2015 and 2014, respectively, which are included in other long‑term liabilities in the accompanying balance sheets. Approximately $1.8 million and $0.9 million of these obligations at December 31, 2015 were assumed in the 2015 acquisitions of Warren and Capitol, respectively.

Leases

Leases

The Partnership had a throughput agreement with GPC with respect to its terminal in Revere, Massachusetts. This agreement was accounted for as an operating lease in 2014 and 2013. On January 14, 2015, the Partnership acquired the Revere terminal from GPC (see Note 3). The Partnership also has lease agreements with the Port of St. Helens for land and for access rights to a rail spur and dock located at its Oregon facility. The Partnership also has terminal and throughput lease arrangements with various unrelated oil terminals and third parties, certain of which arrangements have minimum usage requirements. In addition, the Partnership leases certain gasoline stations from third parties under long‑term arrangements with various expiration dates. The Partnership’s has a long‑term lease agreement with Getty Realty which enables the Partnership to supply and operate certain Getty Realty gasoline station sites.

The Partnership has future commitments, principally for office space and computer equipment, under the terms of operating lease arrangements. The Partnership also leases railcars and barges through various lease arrangements with various expiration dates. The Partnership has rental income from gasoline stations and cobranding arrangements and lease income from space leased to several unrelated third parties at several of our terminals. Additionally, the Partnership has capital leases for other computer equipment and leasehold improvements.

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

Revenue Recognition

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.

Product 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. The Partnership recognizes net exchange differentials due from exchange partners in sales upon delivery of product to an exchange partner.

The Partnership collects trustee taxes, which consist of various pass through taxes collected 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

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, crude oil and ethanol 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. 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 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.

Foreign Currency Transactions

Foreign Currency Transactions

Gains/(losses) realized from transactions denominated in foreign currencies are included in cost of sales in the consolidated statements of operations and totaled ($714,000),  ($25,000) and$162,000 for the years ended December 31, 2015, 2014 and 2013, respectively.

Concentration of Risk

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 in investment‑grade securities. 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 and directly operated convenience stores are located in the Northeast, Maryland and Virginia.

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 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 that the Partnership distributes. Therefore, the Partnership’s volumes in gasoline 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 volumes are generally higher during the first and fourth quarters of the calendar year. These factors may result in fluctuations in the Partnership’s quarterly operating results.

The following table presents the Partnership’s product sales and other revenues as a percentage of the consolidated sales for the years ended December 31:

	2015		2014		2013
Gasoline sales: gasoline and gasoline blendstocks (such as ethanol)	59	%	60	%	58	%
Crude oil sales and crude oil logistics revenue	12	%	14	%	18	%
Distillates (home heating oil, diesel and kerosene), residual oil, natural gas and propane sales	25	%	25	%	23	%
Convenience store sales, rental income and sundry sales	4	%	1	%	1	%
Total	100	%	100	%	100	%

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

Derivative Financial Instruments

The Partnership principally uses derivative instruments, which include regulated exchange-traded futures and options contracts (collectively, “exchange-traded derivatives”) and physical and financial forwards and over-the counter (“OTC”) swaps (collectively, “OTC derivatives”), to reduce its exposure to unfavorable changes in commodity market prices and interest rates. The Partnership uses these exchange-traded and OTC derivatives to hedge commodity price risk associated with its inventory and undelivered forward commodity purchases and sales (“physical forward contracts”) and uses interest rate swap instruments to reduce its exposure to fluctuations in interest rates associated with the Partnership’s credit facilities. The Partnership accounts for derivative transactions in accordance with ASC 815, “Derivatives and Hedging,” and recognizes derivatives instruments as either assets or liabilities in the consolidated balance sheet and measures those instruments at fair value. The changes in fair value of the derivative transactions are presented currently in earnings, unless specific hedge accounting criteria are met.

The fair value of exchange-traded derivative transactions reflects amounts that would be received from or paid to the Partnership’s brokers upon liquidation of these contracts. The fair value of these exchange-traded derivative transactions are presented on a net basis, offset by the cash balances on deposit with the Partnership’s brokers, presented as brokerage margin deposits in the consolidated balance sheets. The fair value of OTC derivative transactions reflects amounts that would be received from or paid to a third party upon liquidation of these contracts under current market conditions. The fair value of these OTC derivative transactions is presented on a gross basis as derivative assets or derivative liabilities in the consolidated balance sheets, unless a legal right of offset exists. The presentation of the change in fair value of the Partnership’s exchange-traded derivatives and OTC derivative transactions depends on the intended use of the derivative and the resulting designation.

Derivatives Accounted for as Hedges – The Partnership utilizes fair value hedges and cash flow hedges to hedge commodity price risk and interest rate risk.

Fair Value Hedges

Derivatives designated as fair value hedges are used to hedge price risk in commodity inventories and principally include exchange-traded futures contracts that are entered into in the ordinary course of business. For a derivative instrument designated as a fair value hedge, the gain or loss is recognized in earnings in the period of change together with the offsetting change in fair value on the hedged item of the risk being hedged. Gains and losses related to fair value hedges are recognized in the consolidated statement of operations through cost of sales. These futures contracts are settled on a daily basis by the Partnership through brokerage margin accounts.

Cash Flow Hedges

Derivatives designated as cash flow hedges are used to hedge interest rate risk from fluctuations in interest rates and may include various interest rate derivative instruments entered into with major financial institutions. For a derivative instrument being designated as a cash flow hedge, the effective portion of the derivative gain or loss is initially reported as a component of other comprehensive income (loss) and subsequently reclassified into the consolidated statement of operations through interest expense in the same period that the hedged exposure affects earnings. The ineffective portion is recognized in the consolidated statement of operations immediately.

Derivatives Not Accounted for as Hedges – The Partnership utilizes petroleum and ethanol commodity contracts, natural gas commodity contracts and foreign currency derivatives to hedge price and currency risk in certain commodity inventories and physical forward contracts.

Petroleum and Ethanol Commodity Contracts

The Partnership uses exchange-traded derivative contracts to hedge price risk in certain commodity inventories which do not qualify for fair value hedge accounting or are not designated by the Partnership as fair value hedges. Additionally, the Partnership uses exchange-traded derivative contracts, and occasionally financial forward and OTC swap agreements, to hedge commodity price exposure associated with its physical forward contracts which are not designated by the Partnership as cash flow hedges. These physical forward contracts, to the extent they meet the definition of a derivative, are considered OTC physical forwards and are reflected as derivative assets or derivative liabilities in the consolidated balance sheet. The related exchange-traded derivative contracts (and financial forward and OTC swaps, if applicable) are also reflected as brokerage margin deposits (and derivative assets or derivative liabilities, if applicable) in the consolidated balance sheet, thereby creating an economic hedge. Changes in fair value of these derivative instruments are recognized in the consolidated statement of operations through cost of sales. These exchange-traded derivatives 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 commodity product purchase and sale activities, it may experience net unbalanced positions for short periods of time as a result of variances in daily purchases and 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, the Partnership is aided by maintaining a constant presence in the marketplace. The Partnership also engages in a controlled trading program for up to an aggregate of 250,000 barrels of commodity products at any one point in time. Changes in fair value of these derivative instruments are recognized in the consolidated statement of operations through cost of sales.

Natural Gas Commodity Contracts

The Partnership uses physical forward purchase contracts to hedge price risk associated with the marketing and selling of natural gas to third-party users. These physical forward purchase commitments for natural gas are typically executed when the Partnership enters into physical forward sale commitments of product for physical delivery. These physical forward contracts, to the extent they meet the definition of a derivative, are reflected as derivative assets and derivative liabilities in the consolidated balance sheet. Changes in fair value of the forward purchase and sale commitments are recognized in the consolidated statement of operations through cost of sales.

Foreign Currency Contracts

The Partnership uses forward foreign currency contracts to hedge certain foreign denominated (Canadian) commodity product purchases. These forward foreign currency contracts are not designated by the Partnership as hedges and are reflected as prepaid expenses and other current assets or accrued expenses and other current liabilities in the consolidated balance sheets. Changes in fair values of these forward foreign currency contracts are reflected in cost of sales.

Margin Deposits

All of the Partnership’s exchange-traded derivative contracts (designated and not designated) are transacted through clearing brokers. The Partnership deposits initial margin with the clearing brokers, along with variation margin, which is paid or received on a daily basis, based upon the changes in fair value of open futures contracts and settlement of closed futures contracts. Cash balances on deposit with clearing brokers and open equity are presented on a net basis within brokerage margin deposits in the consolidated balance sheets.

Please See Note 4 “Derivative Financial Instruments,” for additional information.

Fair Value Measurements

Fair Value Measurements

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Partnership utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. The Partnership primarily applies the market approach for recurring fair value measurements and endeavors to utilize the best available information. Accordingly, the Partnership utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The Partnership is able to classify fair value balances based on the observability of those inputs. The fair value hierarchy that prioritizes the inputs used to measure fair value, giving the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). At each balance sheet reporting date, the Partnership categorizes its financial assets and liabilities using the three levels of the fair value hierarchy defined as follows:

Level 1—Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as the Partnership’s exchange-traded derivative instruments and pension plan assets.

Level 2—Quoted prices in active markets are not available; however, pricing inputs are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Level 2 primarily consists of non-exchange-traded derivatives such as OTC derivatives.

Level 3—Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. Level 3 includes certain OTC forward derivative instruments related to crude oil and propane.

Please see Note18, “Fair Value Measurements,” for additional information.

Net Income Per Limited Partner Unit

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 unitholders, or limited partners’ interest, and to the General Partner’s general partner interest.

Common units outstanding as reported in the accompanying consolidated financial statements at December31, 2015 and 2014 excluded  403,922 and 390,602common 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, 2015
			Limited		General
			Partner		Partner
Numerator:	Total		Interest		Interest		IDRs
Net income attributable to Global Partners LP (1)	$	43,563	$	35,896	$	7,667	$	—
Declared distribution	$	92,059	$	84,055	$	582	$	7,422
Assumed allocation of undistributed net income		(48,496)		(48,159)		(337)		—
Assumed allocation of net income	$	43,563	$	35,896	$	245	$	7,422
Denominator:
Basic weighted average limited partner units outstanding				32,178
Dilutive effect of phantom units				145
Diluted weighted average limited partner units outstanding				32,323
Basic net income per limited partner unit			$	1.12
Diluted net income per limited partner unit			$	1.11

	Year Ended December 31, 2014
			Limited		General
			Partner		Partner
Numerator:	Total		Interest		Interest		IDRs
Net income attributable to Global Partners LP (2)	$	114,709	$	108,728	$	5,981	$	—
Declared distribution	$	78,771	$	73,143	$	593	$	5,035
Assumed allocation of undistributed net income		35,938		35,585		353		—
Assumed allocation of net income	$	114,709	$	108,728	$	946	$	5,035
Denominator:
Basic weighted average limited partner units outstanding				27,420
Dilutive effect of phantom units				82
Diluted weighted average limited partner units outstanding				27,502
Basic net income per limited partner unit			$	3.97
Diluted net income per limited partner unit			$	3.95

(1) As a result of the June 2015 issuance of 3,000,000 common units (see Note15), the general partner interest was reduced to 0.67% from 0.74% and was, based on a weighted average, approximately 0.70%for the year ended December31, 2015.

(2) As a result of the December 2014 issuance of 3,565,000 common units (see Note15), the general partner interest was reduced to 0.74% from 0.83%. The issuance of these common units did not have a material impact on the Partnership’s basic or diluted net income per limited partner unit for the year ended December31, 2014.

	Year Ended December 31, 2013
			Limited		General
			Partner		Partner
Numerator:	Total		Interest		Interest		IDRs
Net income attributable to Global Partners LP	$	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

The board of directors of the General Partner declared the following quarterly cash distributions for the four quarters ended December 31, 2015:

	Per Unit Cash			Distribution Declared for the
Cash Distribution Declaration Date	Distribution Declared			Quarterly Period Ended
April 22, 2015	$	0.6800	(1)	March 31, 2015
July 22, 2015	$	0.6925	(1)	June 30, 2015
October 21, 2015	$	0.6975	(1)	September 30, 2015
January 28, 2016	$	0.4625		December 31, 2015

(1) This declared cash distribution resulted in an incentive distribution to the General Partner, as the holder of the IDRs, and enable the Partnership to exceed its third 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

Accounting Standards or Updates Recently Adopted

In November 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2015-17, “Income Taxes: Balance Sheet Classification of Deferred Taxes.” This standard simplifies the presentation of deferred income taxes and provides presentation requirements to classify deferred tax assets and liabilities as non-current in a classified statement of financial position. The standard is effective for fiscal years beginning after December5, 2016, including interim periods within those fiscal years. The Partnership early adopted this standard as of December31, 2015 and applied the guidance retrospectively. As a result, as of December31, 2014, current deferred taxes included in prepaid expenses and other current assets decreased by $1.1million and long-term deferred income taxes increased by $1.1million. The adoption of this standard did not have a material impact on the Partnership’s consolidated financial statements. See Note 5.

In April 2015, the FASB issued ASU No. 2015-03, “Interest-Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs.” This standard requires debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying value of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by this standard. The amendments in this standard are effective retrospectively for fiscal years, and interim periods within those years, beginning after December 15, 2015. The Partnership adopted this standard as of December31, 2015 and, as a result, reclassed unamortized debt issuance costs of approximately $6.9 million from other assets and $1.1 million from prepaid expenses and other current assets, a total of $8.0 million, to a reduction of senior notes in the accompanying balance sheet as of December31, 2014. The adoption of this standard did not have a material impact on the Partnership’s consolidated financial statements. See Note 8.

Accounting Standards or Updates Not Yet Effective

Accounting Standards or Updates Not Yet Effective

In February 2016, the FASB issued ASU No. 2016-02, “Leases.” This standard amends the existing accounting standards for lease accounting, including requiring lessees to recognize most leases on their balance sheets and making targeted changes to lessor accounting. This standard is effective beginning in the first quarter of 2019. Early adoption of this standard is permitted. The standard requires a modified retrospective transition approach for all leases existing at, or entered into after, the date of initial application, with an option to use certain transition relief. The Partnership is assessing the impact this standard will have on its consolidated financial statements.

In January 2016, the FASB issued ASU No. 2016-01, “Financial Instruments - Recognition and Measurement of Financial Assets and Financial Liabilities”. This standard revises the classification and measurement of investments in certain equity investments and the presentation of certain fair value changes for certain financial liabilities measured at fair value. This standard also requires the change in fair value of many equity investments to be recognized in net income. This standard is effective for interim and annual periods beginning after December 15, 2017, with early adoption permitted. The adoption of this standard is not expected to have a material impact on the Partnership’s consolidated financial statements.

In September 2015, the FASB issued ASU No. 2015-16, “Business Combinations: Simplifying the Accounting for Measurement-Period Adjustments.” This standard eliminates the requirement that an acquirer in a business combination account for measurement-period adjustments retrospectively. Instead, acquirers must recognize measurement-period adjustments during the period in which they determine the amounts, including the effect on earnings of any amounts they would have recorded in previous periods if the accounting had been completed at the acquisition date. The acquirer still must disclose the amounts and reasons for adjustments to the provisional amounts. The acquirer also must disclose, by line item, the amount of the adjustment reflected in the current-period income statement that would have been recognized in previous periods if the adjustment to provisional amounts had been recognized as of the acquisition date. Alternatively, an acquirer may present those amounts separately on the face of the income statement. This new standard is effective for fiscal years beginning after December 15, 2015, including interim periods within those fiscal years. Early adoption is permitted. The adoption of this standard is not expected to have a material impact on the Partnership’s consolidated financial statements.

In July 2015, the FASB issued ASU No. 2015-11, “Simplifying the Measurement of Inventory,” which requires an entity to measure inventory within the scope of the amendment at the lower of cost and net realizable value. Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. The new standard is effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years. The Partnership is assessing the impact this standard will have on its consolidated financial statements.

In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers,” that introduces a new five-step revenue recognition model in which an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This standard also requires disclosures sufficient to enable users to understand the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers, including qualitative and quantitative disclosures about contracts with customers, significant judgments and changes in judgments, and assets recognized from the costs to obtain or fulfill a contract. In July 2015, the FASB approved a one-year deferral of the effective date of the standard to fiscal periods beginning after December 15, 2017. The Partnership is evaluating the new guidance to determine the impact it will have on its consolidated financial statements.

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Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2015

Summary of Significant Accounting Policies

Schedule of inventories (in thousands)

	2015		2014
Distillates: home heating oil, diesel and kerosene	$	156,411	$	163,679
Gasoline		62,467		82,080
Gasoline blendstocks		32,542		33,760
Crude oil		102,253		20,769
Residual oil		12,895		20,602
Propane and other		1,469		5,123
Renewable identification numbers (RINs)		803		2,057
Convenience store inventory		20,112		8,743
Total	$	388,952	$	336,813

Schedule of estimated useful lives of property and equipment

Gasoline station buildings, improvements and storage tanks	15-25	years
Buildings, docks, terminal facilities and improvements	5-25	years
Gasoline station equipment	7	years
Fixtures, equipment and capitalized internal use software	3-7	years

Schedule of product sales and logistics revenue as a percentage of total revenues

	2015		2014		2013
Gasoline sales: gasoline and gasoline blendstocks (such as ethanol)	59	%	60	%	58	%
Crude oil sales and crude oil logistics revenue	12	%	14	%	18	%
Distillates (home heating oil, diesel and kerosene), residual oil, natural gas and propane sales	25	%	25	%	23	%
Convenience store sales, rental income and sundry sales	4	%	1	%	1	%
Total	100	%	100	%	100	%

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, 2015
			Limited		General
			Partner		Partner
Numerator:	Total		Interest		Interest		IDRs
Net income attributable to Global Partners LP (1)	$	43,563	$	35,896	$	7,667	$	—
Declared distribution	$	92,059	$	84,055	$	582	$	7,422
Assumed allocation of undistributed net income		(48,496)		(48,159)		(337)		—
Assumed allocation of net income	$	43,563	$	35,896	$	245	$	7,422
Denominator:
Basic weighted average limited partner units outstanding				32,178
Dilutive effect of phantom units				145
Diluted weighted average limited partner units outstanding				32,323
Basic net income per limited partner unit			$	1.12
Diluted net income per limited partner unit			$	1.11

	Year Ended December 31, 2014
			Limited		General
			Partner		Partner
Numerator:	Total		Interest		Interest		IDRs
Net income attributable to Global Partners LP (2)	$	114,709	$	108,728	$	5,981	$	—
Declared distribution	$	78,771	$	73,143	$	593	$	5,035
Assumed allocation of undistributed net income		35,938		35,585		353		—
Assumed allocation of net income	$	114,709	$	108,728	$	946	$	5,035
Denominator:
Basic weighted average limited partner units outstanding				27,420
Dilutive effect of phantom units				82
Diluted weighted average limited partner units outstanding				27,502
Basic net income per limited partner unit			$	3.97
Diluted net income per limited partner unit			$	3.95

(1) As a result of the June 2015 issuance of 3,000,000 common units (see Note15), the general partner interest was reduced to 0.67% from 0.74% and was, based on a weighted average, approximately 0.70%for the year ended December31, 2015.

(2) As a result of the December 2014 issuance of 3,565,000 common units (see Note15), the general partner interest was reduced to 0.74% from 0.83%. The issuance of these common units did not have a material impact on the Partnership’s basic or diluted net income per limited partner unit for the year ended December31, 2014.

	Year Ended December 31, 2013
			Limited		General
			Partner		Partner
Numerator:	Total		Interest		Interest		IDRs
Net income attributable to Global Partners LP	$	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

Quarterly cash distributions by board of General Partner

	Per Unit Cash			Distribution Declared for the
Cash Distribution Declaration Date	Distribution Declared			Quarterly Period Ended
April 22, 2015	$	0.6800	(1)	March 31, 2015
July 22, 2015	$	0.6925	(1)	June 30, 2015
October 21, 2015	$	0.6975	(1)	September 30, 2015
January 28, 2016	$	0.4625		December 31, 2015

(1) This declared cash distribution resulted in an incentive distribution to the General Partner, as the holder of the IDRs, and enable the Partnership to exceed its third target level distribution with respect to such IDRs.

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Business Combinations (Tables)

12 Months Ended

Dec. 31, 2015

Acquisitions

Schedule of estimated annual intangible asset amortization expense for future years (in thousands)

2016	$	11,011
2017		10,025
2018		9,477
2019		9,477
2020		9,176
Thereafter		26,528
Total intangible assets	$	75,694

Schedule of pro-forma information (in thousands, except per unit data)

	Year Ended December 31,
	2015		2014
Sales	$	10,540,275	$	19,303,900
Net income attributable to Global Partners LP	$	47,555	$	85,058
Net income per limited partner unit, basic	$	1.24	$	2.89
Net income per limited partner unit, diluted	$	1.23	$	2.88

Warren Equities Inc

Acquisitions

Schedule of preliminary allocation of the purchase price to the estimated fair value of the assets acquired and liabilities assumed (in thousands)

Assets purchased:
Accounts receivable	$	9,511
Inventory		19,144
Prepaid expenses and other current assets		11,038
Property and equipment		255,148
Intangibles		38,360
Other non-current assets		16,595
Total identifiable assets purchased		349,796
Liabilities assumed:
Accounts payable		(23,067)
Environmental liabilities		(36,467)
Taxes payable		(5,168)
Accrued expenses		(4,462)
Long-term deferred taxes		(75,501)
Other non-current liabilities		(9,739)
Total liabilities assumed		(154,404)
Net identifiable assets acquired		195,392
Goodwill		186,437
Net assets acquired	$	381,829

Warren Equities Inc | Favorable leasehold interests

Acquisitions

Schedule of estimated annual intangible asset amortization expense for future years (in thousands)

2016	$	152
2017		152
2018		152
2019		152
Total	$	608

Warren Equities Inc | Supply Contracts

Acquisitions

Schedule of estimated annual intangible asset amortization expense for future years (in thousands)

2016	$	3,899
2017		3,899
2018		3,899
2019		3,899
2020		3,899
Thereafter		13,931
Total	$	33,426

Revere terminal

Acquisitions

Schedule of preliminary allocation of the purchase price to the estimated fair value of the assets acquired and liabilities assumed (in thousands)

Assets purchased:
Property and equipment	$	28,481
Total identifiable assets purchased		28,481
Liabilities assumed:
Environmental liabilities		(3,074)
Other non-current liabilities		(1,757)
Total liabilities assumed		(4,831)
Net assets acquired	$	23,650

Capitol Petroleum Group

Acquisitions

Schedule of preliminary allocation of the purchase price to the estimated fair value of the assets acquired and liabilities assumed (in thousands)

Assets purchased:
Inventory	$	346
Property and equipment		149,583
Intangibles		3,000
Other non-current assets		57
Total identifiable assets purchased		152,986
Liabilities assumed:
Financing obligation		(89,613)
Environmental liabilities		(300)
Other non-current liabilities		(2,236)
Total liabilities assumed		(92,149)
Net identifiable assets acquired		60,837
Goodwill		94,854
Net assets acquired	$	155,691

Capitol Petroleum Group | Favorable leasehold interests

Acquisitions

Schedule of estimated annual intangible asset amortization expense for future years (in thousands)

2016	$	1,100
2017		458
Total	$	1,558

Capitol Petroleum Group | Supply Contracts

Acquisitions

Schedule of estimated annual intangible asset amortization expense for future years (in thousands)

2016	$	114
2017		114
2018		114
2019		114
2020		114
Thereafter		163
Total	$	733

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Derivative Financial Instruments (Tables)

12 Months Ended

Dec. 31, 2015

Derivative Financial Instruments

Schedule of notional values of derivative instruments

	Units (1)		Unit of Measure
Exchange-Traded Derivatives
Long		37,785	Thousands of barrels
Short		(44,135)	Thousands of barrels
OTC Derivatives (Petroleum/Ethanol)
Long		7,840	Thousands of barrels
Short		(8,073)	Thousands of barrels
OTC Derivatives (Natural Gas)
Long		9,919	Thousands of decatherms
Short		(9,939)	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)	$	0.7	Millions of Canadian dollars
	$	0.5	Millions of U.S. dollars

(1) Number of open positions and gross notional values do not measure the Partnership’s risk of loss, quantify risk or represent assets or liabilities of the Partnership, but rather indicate the relative size of the derivative instruments and are used in the calculation of the amounts to be exchanged between counterparties upon settlements.

(2) All‑in forward rate Canadian dollars $1.3828 to USD $1.00.

Schedule of the amount of gains and losses from derivatives not involved in a fair value hedging relationship or in a hedging relationship recognized in the consolidated statements of income (in thousands)

The following table presents the gains and losses from the Partnership’s derivative instruments not involved in a hedging relationship recognized in the consolidated statements of operations for the years ended December 31 (in thousands):

	Statement of Gain (Loss)
Derivatives not designated as	Recognized in	December 31,
hedging instruments	Income on Derivatives	2015		2014		2013
Commodity contracts	Cost of sales	$	5,930	$	18,894	$	11,819
Forward foreign currency contracts	Cost of sales		191		25		(162)
Total		$	6,121	$	18,919	$	11,657

Summary of derivatives not designated as either fair value hedges or cash flow hedges and their respective fair values and location

The following table presents the fair value of each classification of the Partnership’s derivative instruments and its location in the consolidated balance sheets at December 31, 2015 and 2014 (in thousands):

		December 31, 2015
		Derivatives		Derivatives Not
		Designated as		Designated as
		Hedging		Hedging
	Balance Sheet Location	Instruments		Instruments		Total
Asset Derivatives:
Exchange-traded derivative contracts	Broker margin deposits	$	83,645	$	11,722	$	95,367
Forward derivative contracts (1)	Derivative assets		—		66,099		66,099
Forward foreign currency contracts	Other assets		—		10		10
Interest rate cap contract	Other assets		—		—		—
Total asset derivatives		$	83,645	$	77,831	$	161,476
Liability Derivatives:
Forward derivative contracts (1)	Derivative liabilities	$	—	$	31,911	$	31,911
Interest rate swap contracts	Other long-term liabilities		—		3,343		3,343
Total liability derivatives		$	—	$	35,254	$	35,254

		December 31, 2014
		Derivatives		Derivatives Not
		Designated as		Designated as
		Hedging		Hedging
	Balance Sheet Location	Instruments		Instruments		Total
Asset Derivatives:
Exchange-traded derivative contracts	Broker margin deposits	$	30,600	$	90,890	$	121,490
Forward derivative contracts (1)	Derivative assets		—		83,826		83,826
Forward foreign currency contracts	Other assets		—		9		9
Interest rate cap contract	Other assets		—		17		17
Total asset derivatives		$	30,600	$	174,742	$	205,342
Liability Derivatives:
Forward derivative contracts (1)	Derivative liabilities	$	—	$	58,507	$	58,507
Interest rate swap contracts	Other long-term liabilities		—		6,696		6,696
Total liability derivatives		$	—	$	65,203	$	65,203

(1) Forward derivative contracts include the Partnership’s petroleum and ethanol physical and financial forwards and OTC swaps.

Fair Value Hedge

Derivative Financial Instruments

Schedule of net gains and losses from derivatives recognized in consolidated statements of operations (in thousands)

The following table presents the gains and losses from the Partnership’s derivative instruments involved in fair value hedging relationships recognized in the consolidated statements of operations for the years ended December 31 (in thousands):

	Statement of Gain (Loss)
	Recognized in Income on	December 31,
	Derivatives	2015		2014		2013
Derivatives in fair value hedging relationship
Exchange-traded futures contracts and OTC derivative contracts for petroleum commodity products	Cost of sales	$	151,344	$	139,473	$	(18,231)
Hedged items in fair value hedge relationship
Physical inventory	Cost of sales	$	(158,987)	$	(141,699)	$	17,949

Cash Flow Hedges

Derivative Financial Instruments

Schedule of fair values of derivative instruments and location in consolidated balance sheets (in thousands)

The following table presents the amount of gains and losses from the Partnership’s derivative instruments designated in cash flow hedging relationships recognized in the consolidated statements of operations and partners’ equity for the years ended December 31 (in thousands):

							Location of Gain (Loss)
	Amount of Gain (Loss)						Reclassified from	Amount of Gain (Loss)
	Recognized in						Accumulated Other	Reclassified from Other
	Other Comprehensive						Comprehensive Income into	Comprehensive Income into
Derivatives Designated in	Income on Derivatives (Effective Portion)						Income (Effective Portion)	Income (Effective Portion)
Cash Flow Hedging Relationship	2015		2014		2013			2015		2014		2013
Interest rate collar	$	—	$	—	$	1,868	Interest expense	$	—	$	—	$	—
Interest rate swaps		3,353		2,766		2,071	Interest expense		—		—		—
Interest rate cap (1)		(17)		(8)		(9)	Interest expense		—		—		—
Total	$	3,336	$	2,758	$	3,930		$	—	$	—	$	—

(1) The interest rate cap was de-designated as a cash flow hedge in June 2014. Prepaid interest rate caplet amounts recognized in accumulated other comprehensive income up until the date of de-designation have been frozen in partner’s equity as of the de-designation date and are being amortized to income through the tenor of the interest rate cap instrument. The change in the fair value of the interest rate cap following de-designation is reflected in earnings and was immaterial for the years ended December 31, 2015 and 2014. As of December 31, 2015, the remaining unamortized prepaid interest rate caplets were $0.3 million and will be amortized over the remaining life for the interest rate cap which expires in April 2016.

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2015

Income Taxes

Schedule of reconciliation of the difference between the statutory federal income tax rate and the effective income tax rate

	2015		2014		2013
Federal statutory income tax rate	35.0	%	34.0	%	34.0	%
State income tax rate, net of federal tax benefit	0.7	%	0.7	%	0.9	%
Foreign income tax	0.6	%	0.1	%	—	%
Partnership income not subject to tax	(40.8)	%	(34.0)	%	(32.9)	%
Effective income tax rate	(4.5)	%	0.8	%	2.0	%

Schedule of the components of the provision for income taxes

	2015		2014		2013
Current:
Federal	$	110	$	(91)	$	(59)
State		1,388		877		542
Foreign		253		188		—
Total current		1,751		974		483
Deferred:
Federal		(1,298)		948		442
State		(2,326)		(959)		(106)
Total deferred		(3,624)		(11)		336
Total	$	(1,873)	$	963	$	819

Schedule of significant components of long-term deferred taxes

	2015		2014
Deferred Income Tax Assets
Accounts receivable allowances	$	2,097	$	413
Environmental liability		17,814		4,211
Asset retirement obligation		3,132		1,490
Intangible assets		—		114
Deferred rent		40		—
UNICAP		747		663
Other		4,477		44
Federal net operating loss carryforwards		13,930		14,203
State net operating loss carryforwards		2,684		1,537
Federal tax credit carryforward		761		13
Total deferred tax assets, gross		45,682		22,688
Valuation allowance		(975)		—
Total deferred tax assets, net	$	44,707	$	22,688
Deferred Income Tax Liabilities
Property and equipment	$	(104,798)	$	(30,041)
Land		(11,527)		(5,605)
Intangible assets		(13,218)		—
Total deferred tax liabilities	$	(129,543)	$	(35,646)
Net deferred tax assets (liabilities)	$	(84,836)	$	(12,958)

Reconciliation of the differences between income before income tax expense and income subject to income tax expense (in thousands)

	2015		2014		2013
Income before income tax expense	$	41,391	$	117,943	$	41,872
Non—taxable income		(48,861)		(117,465)		(41,640)
Income subject to income tax expense	$	(7,470)	$	478	$	232

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Property and Equipment (Tables)

12 Months Ended

Dec. 31, 2015

Property and Equipment

Schedule of components of property and equipment (in thousands)

	2015		2014
Buildings and improvements	$	992,917	$	667,172
Land		450,045		288,929
Fixtures and equipment		40,946		26,577
Construction in process		67,080		66,119
Capitalized internal use software		18,852		7,530
Total property and equipment		1,569,840		1,056,327
Less accumulated depreciation		327,157		231,276
Total	$	1,242,683	$	825,051

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Goodwill and Intangible Assets (Tables)

12 Months Ended

Dec. 31, 2015

Goodwill and Intangible Assets

Summary of roll forward of the Partnership's goodwill (in thousands)

	Goodwill Allocated to
	Wholesale		GDSO
	Reporting		Reporting
	Unit		Unit		Total
Balance at December 31, 2014	$	121,752	$	32,326	$	154,078
Acquisition of Warren		—		186,437		186,437
Acquisition of Capitol		—		94,854		94,854
Balance at December 31, 2015	$	121,752	$	313,617	$	435,369

Schedule of components of intangible assets (dollars in thousands)

	Gross				Net
	Carrying		Accumulated		Intangible		Amortization
	Amount		Amortization		Assets		Period
At December 31, 2015
Intangible assets subject to amortization:
Terminalling services	$	26,365	$	(11,087)	$	15,278	20 years
Customer relationships		43,986		(39,691)		4,295	2-15 years
Supply contracts		77,771		(24,412)		53,359	5-15 years
Favorable leasehold interests		2,960		(794)		2,166	2-5 years
Brand incentive program		1,445		(1,117)		328	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		(511)		268	20 years
Total intangible assets	$	155,694	$	(80,000)	$	75,694
At December 31, 2014
Intangible assets subject to amortization:
Terminalling services	$	26,365	$	(9,752)	$	16,613	20 years
Customer relationships		43,986		(35,996)		7,990	2-15 years
Supply contracts		39,646		(16,345)		23,301	5-15 years
Brand incentive program		1,445		(879)		566	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	$	(65,707)	$	48,902

Schedule of estimated annual intangible asset amortization expense for future years (in thousands)

2016	$	11,011
2017		10,025
2018		9,477
2019		9,477
2020		9,176
Thereafter		26,528
Total intangible assets	$	75,694

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Environmental Liabilities, ARO and RINs (Tables)

12 Months Ended

Dec. 31, 2015

Environmental Liabilities and Renewable Identification Numbers (RINs)

Summary roll forward of the environmental liabilities (in thousands)

	Balance at								Other		Balance at
	December 31,		Additions		Payments in		Dispositions		Adjustments		December 31,
Environmental Liability Related to:	2014		2015		2015		2015		2015		2015
Retail gasoline stations	$	35,792	$	36,767	$	(3,535)	$	(75)	$	(498)	$	68,451
Terminals		1,771		3,074		(63)		—		—		4,782
Total environmental liabilities	$	37,563	$	39,841	$	(3,598)	$	(75)	$	(498)	$	73,233
Current portion	$	3,101									$	5,350
Long-term portion		34,462										67,883
Total environmental liabilities	$	37,563									$	73,233

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Trustee Taxes and Accrued Expenses and Other Current Liabilities (Tables)

12 Months Ended

Dec. 31, 2015

Trustee Taxes and Accrued Expenses and Other Current Liabilities

Schedule of accrued expenses and other current liabilities (in thousands)

	2015		2014
Barging transportation, product storage and other ancillary cost accruals	$	13,385	$	19,843
Employee compensation		16,098		26,827
Accrued interest		12,524		12,839
Customer Advance		—		12,000
RIN and RVO deficiency		367		253
Other		17,954		11,058
Total	$	60,328	$	82,820

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Employee Benefit Plans with Related Party (Tables)

12 Months Ended

Dec. 31, 2015

Employee Benefit Plans with Related Party

Schedule of plan's funded status and the total amounts recognized in the consolidated balance sheets (in thousands)

	December 31,  2015
	Global		GMG
	Pension Plan		Pension Plan		Total
Projected benefit obligation	$	16,338	$	4,593	$	20,931
Fair value of plan assets		13,481		3,405		16,886
Net unfunded pension liability	$	2,857	$	1,188	$	4,045

	December 31,  2014
	Global		GMG
	Pension Plan		Pension Plan		Total
Projected benefit obligation	$	18,333	$	5,282	$	23,615
Fair value of plan assets		14,545		3,478		18,023
Net unfunded pension liability	$	3,788	$	1,804	$	5,592

Schedule of change in benefit obligation for the Pension Plans

	2015		2014		2013
Benefit obligation at beginning of year	$	23,615	$	19,245	$	23,073
Interest cost		801		804		730
Actuarial (gain) loss		(1,925)		5,151		(2,419)
Benefits paid		(1,559)		(1,585)		(2,139)
Benefit obligation at end of year	$	20,932	$	23,615	$	19,245

Schedule of weighted-average actuarial assumptions

	Global Pension Plan			GMG Pension Plan
	2015	2014	2013	2015	2014	2013
Discount rate	4.0%	3.6%	4.4%	4.3%	3.6%	4.4%
Expected return on plan assets	7.0%	7.5%	7.5%	7.0%	7.0%	7.0%

Schedule of estimated future benefit payments (in thousands)

2016	$	2,001
2017		2,436
2018		833
2019		808
2020		1,334
2021—2025		4,933
Total	$	12,345

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Long-Term Incentive Plan (Tables)

12 Months Ended

Dec. 31, 2015

Long-Term Incentive Plan

Summary of the status of the non-vested phantom units

		Weighted
	Number of	Average
	Non-vested	Grant Date
	Units	Fair Value
Outstanding non—vested units at December 31, 2013	498,112	$	39.29
Granted	44,902		39.34
Vested	(10,266)		39.29
Forfeited	—		—
Outstanding non—vested units at December 31, 2014	532,748		39.29
Granted	76,893		35.72
Vested	(13,921)		38.39
Forfeited	—		—
Outstanding non—vested units at December 31, 2015	595,720	$	38.85

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2015

Commitments and Contingencies

Schedule of total future minimum payments under the agreement with non-cancellable terms of one year or more

2016	$	9,000
2017		9,000
2018		9,000
2019		9,000
2020		9,000
Thereafter		40,500
Total	$	85,500

Schedule of future minimum volume purchase requirements

2016	397,600
2017	331,900
2018	330,100
2019	327,700
2020	312,700
Thereafter	828,300
Total	2,528,300

Office Space and Equipment [Member]

Commitments and Contingencies

Schedule of total future minimum payments under leases with non-cancellable terms of one year or more

2016	$	2,816
2017		2,743
2018		2,644
2019		2,650
2020		2,297
Thereafter		13,840
Total	$	26,990

Terminal and Throughput Leases

Commitments and Contingencies

Schedule of total future minimum payments under the agreement with non-cancellable terms of one year or more

2016	$	14,984
2017		8,353
2018		723
2019		132
Total	$	24,192

Gasoline station buildings, improvements and storage tanks

Commitments and Contingencies

Schedule of total future minimum payments under leases with non-cancellable terms of one year or more

2016	$	29,432
2017		26,102
2018		23,365
2019		20,712
2020		18,236
Thereafter		98,193
Total	$	216,040

Schedule of future minimum rental income under non-cancellable operating leases

2016	$	45,125
2017		23,781
2018		7,797
2019		1,212
2020		1,079
Thereafter		17,001
Total	$	95,995

Railcars

Commitments and Contingencies

Schedule of total future minimum payments under leases with non-cancellable terms of one year or more

2016	$	59,625
2017		52,186
2018		45,968
2019		28,532
2020		2,257
Thereafter		608
Total	$	189,176

Barges

Commitments and Contingencies

Schedule of total future minimum payments under leases with non-cancellable terms of one year or more

2016	$	58,256
2017		45,854
2018		36,440
2019		12,223
2020		1,983
Total	$	154,756

Land and Equipment

Commitments and Contingencies

Schedule of total future minimum payments under leases with non-cancellable terms of one year or more

2016	$	223
2017		223
2018		223
2019		223
2020		223
Thereafter		10,128
Total	$	11,243

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Partners' Equity and Cash Distributions (Tables)

12 Months Ended

Dec. 31, 2015

Partners' Equity and Cash Distribution

Schedule of changes in partnership outstanding units

	Limited Partner Units	General Partner Equivalent Units	Total
Balance at December 31, 2013	27,430,563	230,303	27,660,866
Public offering of common units (see Note 15)	3,565,000	—	3,565,000
Balance at December 31, 2014	30,995,563	230,303	31,225,866
Public offering of common units (see Note 15)	3,000,000	—	3,000,000
Balance at December 31, 2015	33,995,563	230,303	34,225,866

Schedule of quarterly cash distributions to the unitholders and the General Partner based on target levels

		Marginal Percentage
	Total Quarterly Distribution	Interest in Distributions
	Target Amount	Unitholders		General Partner
First Target Distribution	upto $0.4625	99.33	%	0.67	%
Second Target Distribution	above $0.4625 up to $0.5375	86.33	%	13.67	%
Third Target Distribution	above $0.5375 up to $0.6625	76.33	%	23.67	%
Thereafter	above $0.6625	51.33	%	48.67	%

Schedule of cash distributions made by the Partnership (in thousands, except per unit data)

	Earned for the	Per Unit
Cash Distribution	Quarter	Cash		Common		General		Incentive		Total Cash
Payment Date	Ended	Distribution		Units		Partner		Distribution		Distribution
2013
02/14/13 (1)(2)	12/31/12	$	0.5700	$	15,636	$	131	$	579	$	16,346
05/15/13 (1)(2)	03/31/13		0.5825		15,979		134		683		16,796
08/14/13 (1)(2)	06/30/13		0.5875		16,116		135		724		16,975
11/14/13 (1)(2)	09/30/13		0.6000		16,459		138		828		17,425
2014
02/14/14 (1)(2)	12/31/13	$	0.6125	$	16,802	$	140	$	932	$	17,874
05/15/14 (1)(2)	03/31/14		0.6250		17,145		143		1,035		18,323
08/14/14 (1)(2)	06/30/14		0.6375		17,487		146		1,139		18,772
11/14/14 (1)(2)	09/30/14		0.6525		17,899		150		1,270		19,319
2015
02/13/15 (3)(4)	12/31/14	$	0.6650	$	20,612	$	154	$	1,591	$	22,357
05/15/15 (3)(4)	03/31/15		0.6800		21,076		157		2,027		23,260
08/14/15 (4)	06/30/15		0.6925		23,543		159		2,618		26,320
11/13/15 (4)	09/30/15		0.6975		23,713		160		2,777		26,650

(1) Prior to the Partnership’s public offering in December 2014 (see Note 15), the limited partner interest was 99.17% and the general partner interest was 0.83%.

(2) This distribution resulted in the Partnership exceeding its second target level distribution for the respective quarter. As a result, the General Partner, as the holder of the IDRs, received an incentive distribution.

(3) Prior to the Partnership’s public offering in June 2015 (see Note 15), the limited partner interest was 99.26% and the general partner interest was 0.74%.

(4) This distribution resulted in the Partnership exceeding its third target level distribution for the respective quarter. As a result, the General Partner, as the holder of the IDRs, received an incentive distribution.

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Related Party Transactions (Tables)

12 Months Ended

Dec. 31, 2015

Related Party Transactions

Schedule of receivables from related parties (in thousands)

	2015		2014
Receivables from GPC	$	—	$	108
Receivables from the General Partner (1)		2,578		3,795
Total	$	2,578	$	3,903

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

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Segment Reporting (Tables)

12 Months Ended

Dec. 31, 2015

Segment Reporting

Summary of financial information for the reportable segments (in thousands)

	Year Ended December 31,
	2015		2014		2013
Wholesale Segment:
Sales
Gasoline and gasoline blendstocks	$	2,714,057	$	7,076,105	$	8,085,225
Crude oil (1)		1,190,560		2,384,018		3,561,428
Other oils and related products (2)		2,006,668		3,436,006		3,559,001
Total	$	5,911,285	$	12,896,129	$	15,205,654
Product margin
Gasoline and gasoline blendstocks	$	66,031	$	71,713	$	43,147
Crude oil (1)		74,182		141,965		92,807
Other oils and related products (2)		67,709		79,376		66,916
Total	$	207,922	$	293,054	$	202,870
Gasoline Distribution and Station Operations Segment (3):
Sales
Gasoline	$	3,289,742	$	3,241,620	$	3,231,925
Station operations (4)		381,194		165,756		146,503
Total	$	3,670,936	$	3,407,376	$	3,378,428
Product margin
Gasoline	$	276,848	$	189,439	$	150,147
Station operations (4)(5)		178,487		93,939		78,833
Total	$	455,335	$	283,378	$	228,980
Commercial Segment:
Sales	$	732,631	$	966,449	$	1,005,526
Product margin	$	29,201	$	29,716	$	28,359
Combined sales and Product margin:
Sales	$	10,314,852	$	17,269,954	$	19,589,608
Product margin (6)	$	692,458	$	606,148	$	460,209
Depreciation allocated to cost of sales		(94,789)		(61,361)		(55,653)
Combined gross profit	$	597,669	$	544,787	$	404,556

(1) Crude oil consists of the Partnership’s crude oil sales and revenue from its logistics activities.

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

(3) The GDSO segment for 2015 includes the results of the January 2015 acquisition of Warren and the June 2015 acquisition of Capitol (see Note 3). As the Warren assets and the Capitol assets were not in place prior to 2015, the above results are not directly comparable to the prior periods.

(4) Station operations primarily consist of convenience store sales and rental income.

(5) For the years ended December 31, 2014 and 2013, station operations includes the reclass of loss (gain) on sale and disposition of assets from product margin to operating expenses to conform to the Partnership’s current presentation.

(6) Product margin is a non-GAAP financial measure used by management and external users of the Partnership’s consolidated financial statements to assess its business. The table above includes a reconciliation of product margin on a combined basis to gross profit, a directly comparable GAAP measure.

Schedule of reconciliation of the totals reported for the reportable segments to the applicable line items in the consolidated financial statements (in thousands)

	2015		2014		2013
Combined gross profit	$	597,669	$	544,787	$	404,556
Operating costs and expenses not allocated to operating segments:
Selling, general and administrative expenses		177,043		153,961		115,491
Operating expenses		290,307		204,070		185,713
Amortization expense		13,499		18,867		19,216
Loss (gain) on sale and disposition of assets		2,097		2,182		(1,273)
Total operating costs and expenses		482,946		379,080		319,147
Operating income		114,723		165,707		85,409
Interest expense		(73,332)		(47,764)		(43,537)
Income tax benefit (expense)		1,873		(963)		(819)
Net income		43,264		116,980		41,053
Net loss (income) attributable to noncontrolling interest		299		(2,271)		1,562
Net income attributable to Global Partners LP	$	43,563	$	114,709	$	42,615

Schedule of total assets by reportable segment (in thousands)

		Wholesale		Commercial		GDSO		Unallocated		Total
December 31, 2015	$	774,352	$	3,224	$	1,392,397	$	493,702	$	2,663,675
December 31, 2014	$	807,708	$	3,827	$	622,860	$	596,422	$	2,030,817

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Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2015

Fair Value Measurements

Schedule of financial assets and financial liabilities measured at fair value on a recurring basis (in thousands)

	Fair Value at December 31, 2015
							Cash Collateral
	Level 1		Level 2		Level 3		Netting		Total
Assets:
Forward derivative contracts (1)	$	—	$	62,382	$	3,717	$	—	$	66,099
Foreign currency derivatives		—		10		—		—		10
Interest rate cap		—		—		—		—		—
Exchange-traded/cleared derivative instruments (2)		95,367		—		—		(64,040)		31,327
Pension plan		16,886		—		—		—		16,886
Total assets	$	112,253	$	62,392	$	3,717	$	(64,040)	$	114,322
Liabilities:
Forward derivative contracts (1)	$	—	$	(27,602)	$	(3,653)	$	—	$	(31,255)
Swap agreements and options		—		(656)		—		—		(656)
Interest rate swaps		—		(3,343)		—		—		(3,343)
Total liabilities	$	—	$	(31,601)	$	(3,653)	$	—	$	(35,254)

	Fair Value at December 31, 2014
							Cash Collateral
	Level 1		Level 2		Level 3		Netting		Total
Assets:
Forward derivative contracts (1)	$	—	$	81,421	$	2,405	$	—	$	83,826
Foreign currency derivatives		—		9		—		—		9
Interest rate cap		—		17		—		—		17
Exchange-traded/cleared derivative instruments (2)		121,490		—		—		(104,292)		17,198
Pension plan		18,023		—		—		—		18,023
Total assets	$	139,513	$	81,447	$	2,405	$	(104,292)	$	119,073
Liabilities:
Forward derivative contracts (1)	$	—	$	(28,500)	$	(27,928)	$	—	$	(56,428)
Swap agreements and options		—		(2,079)		—		—		(2,079)
Interest rate swaps		—		(6,696)		—		—		(6,696)
Total liabilities	$	—	$	(37,275)	$	(27,928)	$	—	$	(65,203)

(1) Forward derivative contracts include the Partnership’s petroleum and ethanol physical and financial forwards and OTC swaps

(2) Amount includes the effect of cash balances on deposit with clearing brokers.

Carrying value and fair value of the Partnership’s senior notes (in thousands)

	December 31, 2015					December 31, 2014
	Carrying			Fair		Carrying		Fair
	Value			Value		Value		Value
6.25% Notes		$	375,000	$	307,500	$	375,000	$	358,594
7.00% Notes		$	300,000	$	249,000	$	—	$	—

Schedule of fair value measurement to changes in significant unobservable inputs

Significant			ImpactonFairValue
Unobservable Input	Position	ChangetoInput	Measurement
Location basis	Long	Increase(decrease)	Gain (loss)
Location basis	Short	Increase(decrease)	Loss (gain)
Transportation	Long	Increase(decrease)	Gain (loss)
Transportation	Short	Increase(decrease)	Loss (gain)
Throughput costs	Long	Increase(decrease)	Gain (loss)
Throughput costs	Short	Increase(decrease)	Loss(gain)

Summary of the changes in fair value of Level 3 financial assets and liabilities (in thousands)

Fair value at December 31, 2014	$	(25,523)
Transfers into Level 3 (1)(2)		516
Realized and unrealized gains (losses) recorded in cost of sales		25,071
Fair value at December 31, 2015	$	64

(1) Transfers from Level 2 to Level 3 were due to certain market inputs associated with propane that were previously considered observable that became unobservable during the year ended December 31, 2015, given increased volatility in the market for this product.

(2) The Partnership’s policy is to recognize transfers between levels with the fair value hierarchy as of the beginning of the reporting period.

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Changes in Accumulated Other Comprehensive (Income) Loss (Tables)

12 Months Ended

Dec. 31, 2015

Changes in Accumulated Other Comprehensive (Income) Loss

Schedule of changes in accumulated other comprehensive loss (in thousands)

	Pension Plan		Derivatives		Total
Balance at December 31, 2013	$	(454)	$	(10,856)	$	(11,310)
Other comprehensive (loss) income before reclassifications of gain (loss)		(4,660)		3,151		(1,509)
Amount of gain (loss) reclassified from accumulated other comprehensive (loss) income		(433)		—		(433)
Total comprehensive (loss) income		(5,093)		3,151		(1,942)
Balance at December 31, 2014		(5,547)		(7,705)		(13,252)
Other comprehensive income before reclassifications of gain (loss)		1,192		4,047		5,239
Amount of gain (loss) reclassified from accumulated other comprehensive (loss) income		(81)		—		(81)
Total comprehensive income		1,111		4,047		5,158
Balance at December 31, 2015	$	(4,436)	$	(3,658)	$	(8,094)

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Quarterly Financial Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2015

Quarterly Financial Data (Unaudited)

Schedule of unaudited quarterly financial data (in thousands, except per unit amounts)

	First		Second		Third		Fourth		Total
Year ended December 31, 2015
Sales	$	2,979,116	$	2,680,088	$	2,486,203	$	2,169,445	$	10,314,852
Gross profit (1)	$	168,558	$	144,188	$	152,299	$	132,624	$	597,669
Net income (loss) (1)(2)(3)	$	30,409	$	7,614	$	8,146	$	(2,905)	$	43,264
Net income (loss) attributable to Global Partners LP	$	30,415	$	7,218	$	8,212	$	(2,282)	$	43,563
Limited partners’ interest in net income (loss)	$	28,236	$	4,547	$	5,380	$	(2,267)	$	35,896
Basic net income (loss) per limited partner unit	$	0.92	$	0.15	$	0.16	$	(0.70)	$	1.12
Diluted net income (loss) per limited partner unit	$	0.92	$	0.15	$	0.16	$	(0.70)	$	1.11
Cash distributions per limited partner unit (5)	$	0.6650	$	0.6800	$	0.6925	$	0.6975	$	2.74

	First		Second		Third		Fourth		Total
Year ended December 31, 2014
Sales	$	5,116,928	$	4,569,620	$	4,050,458	$	3,532,948	$	17,269,954
Gross profit (4)	$	159,024	$	87,685	$	155,435	$	142,643	$	544,787
Net income (loss) (2)(4)	$	57,154	$	(12,278)	$	43,622	$	28,482	$	116,980
Net income (loss) attributable to Global Partners LP	$	57,010	$	(12,719)	$	42,508	$	27,910	$	114,709
Limited partners’ interest in net (loss) income	$	55,502	$	(13,752)	$	40,885	$	26,093	$	108,728
Basic net income (loss) per limited partner unit	$	2.04	$	(0.50)	$	1.50	$	0.93	$	3.97
Diluted net income (loss) per limited partner unit	$	2.03	$	(0.50)	$	1.50	$	0.93	$	3.95
Cash distributions per limited partner unit (5)	$	0.6125	$	0.6250	$	0.6375	$	0.6525	$	2.53

(1) Includes a $5.0 million charge related to a customer dispute in the first quarter of 2015.

(2) Includes the following charges in connection with the acquisition of Warren: (i)acquisition costs of $4.4 million and $1.0 million in the first and second quarters of 2015, respectively, and $1.7 million in the fourth quarter of 2014; and (ii) a restructuring charge of $2.3 million in the first quarter of 2015.

(3) Includes acquisition costs in connection with the acquisition of Capitol of $3.1 million and $0.1 million in the second and third quarters of 2015, respectively.

(4) Includes the reclass of loss on sale and disposition of assets within GDSO’s station operations product margin to operating expenses of $0.7million, $0.4million and $1.1million in the first, second and fourth quarters of 2014, respectively, to conform to the Partnership’s current presentation.

(5) Cash distributions declared in one calendar quarter are paid in the following calendar quarter.

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Supplemental Guarantor Condensed Consolidating Financial Information (Tables)

12 Months Ended

Dec. 31, 2015

Supplemental Guarantor Condensed Consolidating Financial Statements

Schedule of condensed consolidating balance sheets

Condensed Consolidating Balance Sheet

December 31, 2015

(In thousands)

		Issuer	Non-
	Guarantor		Guarantor
	Subsidiaries		Subsidiary		Eliminations		Consolidated
Assets
Current assets:
Cash and cash equivalents	$	—	$	4,690	$	(3,574)	$	1,116
Accounts receivable, net		311,079		275		—		311,354
Accounts receivable - affiliates		2,745		746		(913)		2,578
Inventories		388,952		—		—		388,952
Brokerage margin deposits		31,327		—		—		31,327
Derivative assets		66,099		—		—		66,099
Prepaid expenses and other current assets		65,376		233		—		65,609
Total current assets		865,578		5,944		(4,487)		867,035
Property and equipment, net		1,203,251		39,432		—		1,242,683
Intangible assets, net		75,694		—		—		75,694
Goodwill		349,306		86,063		—		435,369
Other assets		42,894		—		—		42,894
Total assets	$	2,536,723	$	131,439	$	(4,487)	$	2,663,675
Liabilities and partners' equity
Current liabilities:
Cash overdraft	$	3,574	$	—	$	(3,574)	$	—
Accounts payable		303,242		539		—		303,781
Accounts payable - affiliates		746		167		(913)		—
Working capital revolving credit facility - current portion		98,100		—		—		98,100
Environmental liabilities - current portion		5,350		—		—		5,350
Trustee taxes payable		95,264		—		—		95,264
Accrued expenses and other current liabilities		59,742		586		—		60,328
Derivative liabilities		31,911		—		—		31,911
Total current liabilities		597,929		1,292		(4,487)		594,734
Working capital revolving credit facility - less current portion		150,000		—		—		150,000
Revolving credit facility		269,000		—		—		269,000
Senior notes		656,564		—		—		656,564
Environmental liabilities - less current portion		67,883		—		—		67,883
Financing obligation		89,790		—		—		89,790
Deferred tax liabilities		84,836		—		—		84,836
Other long-term liabilities		56,884		—		—		56,884
Total liabilities		1,972,886		1,292		(4,487)		1,969,691
Partners' equity
Global Partners LP equity		563,837		83,952		—		647,789
Noncontrolling interest		—		46,195		—		46,195
Total partners' equity		563,837		130,147		—		693,984
Total liabilities and partners' equity	$	2,536,723	$	131,439	$	(4,487)	$	2,663,675

Condensed Consolidating Balance Sheet

December 31, 2014

(In thousands)

	Issuer		Non-
	Guarantor		Guarantor
	Subsidiaries		Subsidiary		Eliminations		Consolidated
Assets
Current assets:
Cash and cash equivalents	$	2,560	$	2,678	$	—	$	5,238
Accounts receivable, net		456,423		1,307		—		457,730
Accounts receivable - affiliates		4,584		820		(1,501)		3,903
Inventories		336,813		—		—		336,813
Brokerage margin deposits		17,198		—		—		17,198
Derivative assets		83,826		—		—		83,826
Prepaid expenses and other current assets		53,681		634		—		54,315
Total current assets		955,085		5,439		(1,501)		959,023
Property and equipment, net		778,385		46,666		—		825,051
Intangible assets, net		45,870		3,032		—		48,902
Goodwill		68,015		86,063		—		154,078
Other assets		43,763		—		—		43,763
Total assets	$	1,891,118	$	141,200	$	(1,501)	$	2,030,817
Liabilities and partners' equity
Current liabilities:
Accounts payable	$	455,629	$	990	$	—	$	456,619
Accounts payable - affiliates		820		681		(1,501)		—
Line of credit		—		700		—		700
Environmental liabilities - current portion		3,101		—		—		3,101
Trustee taxes payable		105,744		—		—		105,744
Accrued expenses and other current liabilities		81,686		1,134		—		82,820
Derivative liabilities		58,507		—		—		58,507
Total current liabilities		705,487		3,505		(1,501)		707,491
Working capital revolving credit facility - less current portion		100,000		—		—		100,000
Revolving credit facility		133,800		—		—		133,800
Senior notes		360,096		—		—		360,096
Environmental liabilities - less current portion		34,462		—		—		34,462
Deferred tax liabilities		12,958		—		—		12,958
Other long-term liabilities		45,854		—		—		45,854
Total liabilities		1,392,657		3,505		(1,501)		1,394,661
Partners' equity
Global Partners LP equity		498,461		88,481		—		586,942
Noncontrolling interest		—		49,214		—		49,214
Total partners' equity		498,461		137,695		—		636,156
Total liabilities and partners' equity	$	1,891,118	$	141,200	$	(1,501)	$	2,030,817

Schedule of condensed consolidating statements of income

Condensed Consolidating Statement of Operations

For the Year Ended December 31, 2015

(In thousands)

			Non-
	Guarantor		Guarantor
	Subsidiaries		Subsidiary		Eliminations		Consolidated
Sales	$	10,306,493	$	23,549	$	(15,190)	$	10,314,852
Cost of sales		9,722,340		10,033		(15,190)		9,717,183
Gross profit		584,153		13,516		—		597,669
Costs and operating expenses:
Selling, general and administrative expenses		174,925		2,118		—		177,043
Operating expenses		281,201		9,106		—		290,307
Amortization expense		10,467		3,032		—		13,499
Loss on sale and disposition of assets		2,097		—		—		2,097
Total costs and operating expenses		468,690		14,256		—		482,946
Operating income (loss)		115,463		(740)		—		114,723
Interest expense		(73,324)		(8)		—		(73,332)
Income (loss) before income tax expense		42,139		(748)		—		41,391
Income tax expense		1,873		—		—		1,873
Net income (loss)		44,012		(748)		—		43,264
Net loss attributable to noncontrolling interest		—		299		—		299
Net income (loss) attributable to Global Partners LP		44,012		(449)		—		43,563
Less: General partner's interest in net income, including incentive distribution rights		7,667		—		—		7,667
Limited partners' interest in net income (loss)	$	36,345	$	(449)	$	—	$	35,896

Condensed Consolidating Statement of Operations

For the Year Ended December 31, 2014

(In thousands)

			Non-
	Guarantor		Guarantor
	Subsidiaries		Subsidiary		Eliminations		Consolidated
Sales	$	17,256,583	$	39,347	$	(25,976)	$	17,269,954
Cost of sales		16,743,163		7,980		(25,976)		16,725,167
Gross profit		513,420		31,367		—		544,787
Costs and operating expenses:
Selling, general and administrative expenses		150,964		2,997		—		153,961
Operating expenses		192,512		11,558		—		204,070
Amortization expense		7,846		11,021		—		18,867
Loss on sale and disposition of assets		2,182		—		—		2,182
Total costs and operating expenses		353,504		25,576		—		379,080
Operating income (loss)		159,916		5,791		—		165,707
Interest expense		(47,651)		(113)		—		(47,764)
Income (loss) before income tax expense		112,265		5,678		—		117,943
Income tax expense		(963)		—		—		(963)
Net income		111,302		5,678		—		116,980
Net (income) loss attributable to noncontrolling interest		—		(2,271)		—		(2,271)
Net income attributable to Global Partners LP		111,302		3,407		—		114,709
Less: General partner's interest in net income, including incentive distribution rights		5,981		—		—		5,981
Limited partners' interest in net income	$	105,321	$	3,407	$	—	$	108,728

Condensed Consolidating Statement of Operations

For the Year Ended December 31, 2013

(In thousands)

			Non-
	Guarantor		Guarantor
	Subsidiaries		Subsidiaries		Eliminations		Consolidated
Sales	$	19,575,042	$	28,948	$	(14,382)	$	19,589,608
Cost of sales		19,194,385		5,049		(14,382)		19,185,052
Gross profit		380,657		23,899		—		404,556
Costs and operating expenses:
Selling, general and administrative expenses		110,228		5,263		—		115,491
Operating expenses		175,284		10,429		—		185,713
Amortization expense		7,106		12,110		—		19,216
Gain on sale and disposition of assets		(1,273)		—		—		(1,273)
Total costs and operating expenses		291,345		27,802		—		319,147
Operating income (loss)		89,312		(3,903)		—		85,409
Interest expense		(43,536)		(1)		—		(43,537)
Income (loss) before income tax expense		45,776		(3,904)		—		41,872
Income tax expense		(819)		—		—		(819)
Net income (loss)		44,957		(3,904)		—		41,053
Net loss attributable to noncontrolling interest		—		1,562		—		1,562
Net income (loss) attributable to Global Partners LP		44,957		(2,342)		—		42,615
Less: General partner's interest in net income, including incentive distribution rights		3,521		—		—		3,521
Limited partners' interest in net income	$	41,436	$	(2,342)	$	—	$	39,094

Schedule of condensed consolidating statements of cash flows

Condensed Consolidating Statement of Cash Flows

For the Year Ended December 31, 2015

(In thousands)

	(Issuer)		Non-
	Guarantor		Guarantor
	Subsidiaries		Subsidiary		Consolidated
Cash flows from operating activities
Net cash provided by operating activities	$	50,309	$	12,197	$	62,506
Cash flows from investing activities
Acquisitions		(561,170)		—		(561,170)
Capital expenditures		(90,240)		(2,685)		(92,925)
Proceeds from sale of property and equipment		4,331		—		4,331
Net cash used in investing activities		(647,079)		(2,685)		(649,764)
Cash flows from financing activities
Proceeds from issuance of common units, net		109,305		—		109,305
Borrowings from working capital revolving credit facility		148,100		—		148,100
Borrowings from revolving credit facility		135,200		—		135,200
Proceeds from senior notes, net of discount		295,338		—		295,338
Payments on line of credit		—		(700)		(700)
Repurchase of common units		(3,892)		—		(3,892)
Noncontrolling interest capital contribution		9,360		(6,800)		2,560
Distribution to noncontrolling interest		(5,280)		—		(5,280)
Distributions to partners		(97,495)		—		(97,495)
Net cash provided by (used in) financing activities		590,636		(7,500)		583,136
Cash and cash equivalents
(Decrease) increase in cash and cash equivalents		(6,134)		2,012		(4,122)
Cash and cash equivalents at beginning of year		2,560		2,678		5,238
Cash and cash equivalents at end of year	$	(3,574)	$	4,690	$	1,116

Condensed Consolidating Statement of Cash Flows

For the Year Ended December 31, 2014

(In thousands)

	(Issuer)		Non-
	Guarantor		Guarantor
	Subsidiaries		Subsidiary		Consolidated
Cash flows from operating activities
Net cash provided by operating activities	$	321,319	$	23,583	$	344,902
Cash flows from investing activities
Capital expenditures		(78,863)		(16,251)		(95,114)
Proceeds from sale of property and equipment		4,021		—		4,021
Net cash used in investing activities		(74,842)		(16,251)		(91,093)
Cash flows from financing activities
Proceeds from public offering, net		137,844		—		137,844
Payments on working capital revolving credit facility		(227,000)		—		(227,000)
Payments on revolving credit facility		(300,900)		—		(300,900)
Payments on line of credit		—		(3,000)		(3,000)
Proceeds from senior notes, net of discount		258,903		—		258,903
Repayment of senior notes		(40,244)		—		(40,244)
Repurchase of common units		(8,632)		—		(8,632)
Noncontrolling interest capital contribution		10,700		(2,500)		8,200
Distribution to noncontrolling interest		(9,200)		—		(9,200)
Distributions to partners		(73,759)		—		(73,759)
Net cash used in financing activities		(252,288)		(5,500)		(257,788)
Cash and cash equivalents
(Decrease) increase in cash and cash equivalents		(5,811)		1,832		(3,979)
Cash and cash equivalents at beginning of year		8,371		846		9,217
Cash and cash equivalents at end of year	$	2,560	$	2,678	$	5,238

Condensed Consolidating Statement of Cash Flows

For the Year Ended December 31, 2013

(In thousands)

	(Issuer)		Non-
	Guarantor		Guarantor
	Subsidiaries		Subsidiary		Consolidated
Cash flows from operating activities
Net cash provided by operating activities	$	240,699	$	14,448	$	255,147
Cash flows from investing activities
Acquisitions		(94,179)		(91,083)		(185,262)
Capital expenditures		(53,484)		(13,648)		(67,132)
Proceeds from sale of property and equipment		9,179		8		9,187
Net cash used in investing activities		(138,484)		(104,723)		(243,207)
Cash flows from financing activities
Payments on working capital revolving credit facility		(97,500)		—		(97,500)
Borrowings from revolving credit facility		12,700		—		12,700
Proceeds from issuance of term loan		115,000		—		115,000
Repayment of term loan		(115,000)		—		(115,000)
Borrowings from line of credit		—		3,700		3,700
Proceeds from senior notes, net of discount		147,900		—		147,900
Repurchase of common units		(4,590)		—		(4,590)
Repurchased units withheld for tax obligations		(2,086)		—		(2,086)
Noncontrolling interest capital contribution		(85,996)		87,421		1,425
Distribution to noncontrolling interest		(2,920)		—		(2,920)
Distributions to partners		(67,329)		—		(67,329)
Net cash used in (provided by) financing activities		(99,821)		91,121		(8,700)
Cash and cash equivalents
Increase in cash and cash equivalents		2,394		846		3,240
Cash and cash equivalents at beginning of year		5,977		—		5,977
Cash and cash equivalents at end of year	$	8,371	$	846	$	9,217

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Organization and Basis of Presentation (Details)			1 Months Ended					3 Months Ended	6 Months Ended	7 Months Ended	12 Months Ended
	Jan. 07, 2015 store	Dec. 05, 2014 shares	Jun. 30, 2015	May. 31, 2015	Mar. 31, 2015 shares	Dec. 31, 2014 shares	Nov. 30, 2014	Mar. 31, 2015 shares	Jun. 15, 2015	Dec. 31, 2015 shares	Dec. 31, 2015 item shares	Dec. 31, 2014 shares
Organization
Number of owned, leased and/or supplied gasoline stations | item											1,509
Number of convenience stores | item											281
General partner interest (as a percent)			0.67%	0.74%		0.74%	0.83%
Number of common units held						30,604,961				33,506,844	33,506,844	30,604,961
Number of common units sold		3,565,000						3,000,000				3,565,000
Affiliates of general partner
Organization
General partner interest (as a percent)											21.90%
Number of common units held										7,434,775	7,434,775
Limited partner ownership interest (as a percent)											21.90%
Decrease in number of common units held											4,305,522
Affiliates of general partner | Directors and Chief Executive Officers
Organization
Number of common units held										2,306,960	2,306,960
AE Holdings
Organization
Limited partner ownership interest before transaction (as a percent)												37.90%
Limited partner units owned before transaction											5,850,000
Number of common units sold					1,956,234
Warren Equities Inc
Organization
Number of convenience stores | store	147
Percentage of outstanding membership interests acquired	100.00%
Number of common units sold											3,565,000
Members of Slifka family
Organization
General partner interest (as a percent)									0.74%	0.67%
Members of Slifka family | AE Holdings
Organization
Number of common units held										1,586,806	1,586,806

XML

Summary of Significant Accounting Policies (Details)	Jan. 07, 2015	Dec. 31, 2013	Feb. 28, 2013	Feb. 15, 2013	Feb. 01, 2013
Warren Equities Inc
Summary of Significant Accounting Policies
Percentage of outstanding membership interests acquired	100.00%
Basin Transload LLC
Summary of Significant Accounting Policies
Percentage of outstanding membership interests acquired		60.00%	60.00%		60.00%
Cascade Kelly
Summary of Significant Accounting Policies
Percentage of outstanding membership interests acquired				100.00%

XML

Summary of Significant Accounting Policies - Inventories (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Inventories
Total	$ 388,952	$ 336,813
Positive exchange balances on inventory exchange agreements accounted for as accounts receivable	3,400	3,900
Negative exchange balances on inventory exchange agreements accounted for as accounts payable	12,100	16,500
Distillates: home heating oil, diesel and kerosene
Inventories
Total	156,411	163,679
Gasoline
Inventories
Total	62,467	82,080
Gasoline blendstocks
Inventories
Total	32,542	33,760
Crude Oil
Inventories
Total	102,253	20,769
Residual Oil
Inventories
Total	12,895	20,602
Propane and other
Inventories
Total	1,469	5,123
Renewable identification numbers (RINs)
Inventories
Total	803	2,057
Convenience store inventory
Inventories
Total	$ 20,112	$ 8,743

XML

Summary of Significant Accounting Policies - Property (Details)	12 Months Ended
	Dec. 31, 2015
Gasoline station buildings, improvements and storage tanks | Minimum
Property and Equipment
Estimated useful life	15 years
Gasoline station buildings, improvements and storage tanks | Maximum
Property and Equipment
Estimated useful life	25 years
Buildings, docks, terminal facilities and improvements | Minimum
Property and Equipment
Estimated useful life	5 years
Buildings, docks, terminal facilities and improvements | Maximum
Property and Equipment
Estimated useful life	25 years
Gasoline station equipment
Property and Equipment
Estimated useful life	7 years
Fixtures, equipment and capitalized internal use software | Minimum
Property and Equipment
Estimated useful life	3 years
Fixtures, equipment and capitalized internal use software | Maximum
Property and Equipment
Estimated useful life	7 years

XML

Summary of Significant Accounting Policies - Intangibles, impairment (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015 USD ($)
Impairment Long-Lived Assets
Long-lived assets used at crude oil terminals	$ 39.4
Minimum
Intangibles
Estimated economic useful life	2 years
Maximum
Intangibles
Estimated economic useful life	20 years

XML

Summary of Significant Accounting Policies - Goodwill thru For Curr (Details)	12 Months Ended
	Dec. 31, 2015 USD ($) item	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)	Jun. 01, 2015 USD ($)	Jan. 07, 2015 USD ($)
Goodwill
Goodwill	$ 435,369,000	$ 154,078,000
Income Taxes
Number of wholly owned subsidiaries which are taxable for federal and state income tax purposes | item	1
Foreign Currency Transactions
Gains/(losses) realized from transactions denominated in foreign currencies	$ (714,000)	(25,000)	$ 162,000
Other long-term liabilities
Asset Retirement Obligations
Total assets retirement obligations	7,800,000	3,800,000
Capitol Petroleum Group
Goodwill
Goodwill				$ 94,854,000
Asset Retirement Obligations
Asset retirement obligation assumed	900,000
Warren Equities Inc
Goodwill
Goodwill					$ 186,437,000
Asset Retirement Obligations
Asset retirement obligation assumed	1,800,000
Wholesale Segment
Goodwill
Goodwill	121,752,000	121,752,000
Impairment of goodwill	0	0	0
Wholesale Segment | Scenario, Forecast [Member]
Goodwill
Impairment of goodwill	121,700,000
GDSO
Goodwill
Goodwill	313,617,000	32,326,000
Impairment of goodwill	$ 0	$ 0	$ 0

XML

Summary of Significant Accounting Policies - Risk(Details) - Sales - Product	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Concentration of Risk
Percentage of total sales	100.00%	100.00%	100.00%
Gasoline sales: gasoline and gasoline blendstocks (such as ethanol)
Concentration of Risk
Percentage of total sales	59.00%	60.00%	58.00%
Crude oil sales and crude oil logistics revenue
Concentration of Risk
Percentage of total sales	12.00%	14.00%	18.00%
Distillates (home heating oil, diesel and kerosene), residual oil, natural gas and propane sales
Concentration of Risk
Percentage of total sales	25.00%	25.00%	23.00%
Convenience store sales, rental income and sundry sales
Concentration of Risk
Percentage of total sales	4.00%	1.00%	1.00%

XML

Summary of Significant Accounting Policies - Derivatives (Details)	12 Months Ended
	Dec. 31, 2015 bbl
Derivatives not designated as hedging instruments | Commodity product | Maximum
Derivative Financial Instruments
Aggregate units of products in a controlled trading program	250,000

XML

Summary of Significant Accounting Policies - NI per unit (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Net Income Per Limited Partner Unit
Repurchased units not deemed outstanding	403,922				390,602				403,922	390,602
Net income attributable to Global Partners LP	$ (2,282)	$ 8,212	$ 7,218	$ 30,415	$ 27,910	$ 42,508	$ (12,719)	$ 57,010	$ 43,563	$ 114,709	$ 42,615
Declared distribution									92,059	78,771	69,070
Assumed allocation of undistributed net income									48,496	35,938	(26,455)
Assumed allocation of net income									$ 43,563	$ 114,709	$ 42,615
Denominator:
Basic weighted average limited partner units outstanding									32,178,000	27,420,000	27,329,000
Diluted weighted average limited partner units outstanding									32,323,000	27,502,000	27,560,000
Basic net income per limited partner unit (in dollars per unit)	$ (0.70)	$ 0.16	$ 0.15	$ 0.92	$ 0.93	$ 1.50	$ (0.50)	$ 2.04	$ 1.12	$ 3.97	$ 1.43
Diluted net income per limited partner unit (in dollars per unit)	$ (0.70)	$ 0.16	$ 0.15	$ 0.92	$ 0.93	$ 1.50	$ (0.50)	$ 2.03	$ 1.11	$ 3.95	$ 1.42
Common Unitholders
Net Income Per Limited Partner Unit
Repurchased units not deemed outstanding	403,922				390,602				403,922	390,602
Net income attributable to Global Partners LP									$ 35,896	$ 108,728	$ 39,094
Declared distribution									84,055	73,143	65,356
Assumed allocation of undistributed net income									48,159	35,585	(26,262)
Assumed allocation of net income									$ 35,896	$ 108,728	$ 39,094
Denominator:
Basic weighted average limited partner units outstanding									32,178,000	27,420,000	27,329,000
Dilutive effect of phantom units									145,000	82,000	231,000
Diluted weighted average limited partner units outstanding									32,323,000	27,502,000	27,560,000
Basic net income per limited partner unit (in dollars per unit)									$ 1.12	$ 3.97	$ 1.43
Diluted net income per limited partner unit (in dollars per unit)									$ 1.11	$ 3.95	$ 1.42
General Partner
Net Income Per Limited Partner Unit
Net income attributable to Global Partners LP									$ 7,667	$ 5,981	$ 3,521
Declared distribution									582	593	547
Assumed allocation of undistributed net income									337	353	(193)
Assumed allocation of net income									245	946	354
IDRs
Net Income Per Limited Partner Unit
Declared distribution									7,422	5,035	3,167
Assumed allocation of net income									$ 7,422	$ 5,035	$ 3,167

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Summary of Significant Accounting Policies - Issuance, dividends(Details) - $ / shares					1 Months Ended				12 Months Ended
	Jan. 28, 2016	Oct. 21, 2015	Jul. 22, 2015	Apr. 22, 2015	Jun. 30, 2015	May. 31, 2015	Dec. 31, 2014	Nov. 30, 2014	Dec. 31, 2015	Dec. 31, 2014
Net Income Per Limited Partner Unit
Issuance of common units in connection with acquisition					3,000,000		3,565,000
General partner ownership interest (as a percent)					0.67%	0.74%	0.74%	0.83%
Quarterly cash distribution declared (in dollars per unit)		$ 0.6975	$ 0.6925	$ 0.6800
Subsequent event
Net Income Per Limited Partner Unit
Quarterly cash distribution declared (in dollars per unit)	$ 0.4625
General Partner
Net Income Per Limited Partner Unit
General partner ownership interest (as a percent)					0.74%				0.67%	0.83%
Weighted average
Net Income Per Limited Partner Unit
General partner ownership interest (as a percent)					0.70%

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Summary of Significant Accounting Policies - Adoption (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Deferred Income Tax Liabilities, Net	$ 84,836	$ 12,958
Other Assets, Noncurrent	42,894	43,763
Prepaid Expense and Other Assets, Current	65,609	54,315
Senior Notes, Noncurrent	$ 656,564	360,096
Accounting Standards Update 2015-17 [Member] | Adjustments for New Accounting Principle, Early Adoption [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Deferred Income Tax Liabilities, Net		1,100
Prepaid Expense and Other Assets, Current		(1,100)
Accounting Standards Update 2015-03 [Member] | Adjustments for New Accounting Principle, Early Adoption [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Other Assets, Noncurrent		(6,900)
Prepaid Expense and Other Assets, Current		(1,100)
Senior Notes, Noncurrent		$ (8,000)

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Business Combinations (Details) $ in Thousands					1 Months Ended			3 Months Ended				12 Months Ended
	Jun. 01, 2015 USD ($) item location	Jan. 14, 2015 USD ($)	Jan. 07, 2015 USD ($) store item location	Dec. 05, 2014 shares	Jun. 30, 2015 shares	Jan. 31, 2015 USD ($)	Dec. 31, 2014 USD ($) shares	Sep. 30, 2015 USD ($)	Jun. 30, 2015 USD ($)	Mar. 31, 2015 USD ($) shares	Dec. 31, 2014 USD ($)	Dec. 31, 2015 USD ($) item shares	Dec. 31, 2014 USD ($) shares
Acquisitions
Number of convenience stores | item												281
Number of owned, leased and/or supplied gasoline stations | item												1,509
Number of common units sold | shares				3,565,000						3,000,000			3,565,000
Assets purchased:
Property and equipment												$ 433,200
Liabilities assumed:
Goodwill							$ 154,078				$ 154,078	435,369	$ 154,078
Sale Leaseback Transaction, Net Book Value [Abstract]
Financing obligation												89,790
Estimated remaining amortization expense
2016												11,011
2017												10,025
2018												9,477
2019												9,477
2020												9,176
Thereafter												26,528
Total							$ 48,902				48,902	$ 75,694	48,902
Acquisition related costs
Restructuring Charges										$ 2,300
Summary of the purchase price
Number of common units issued | shares					3,000,000		3,565,000
Minimum
Intangible assets acquired
Amortization Period												2 years
Maximum
Intangible assets acquired
Amortization Period												20 years
Favorable leasehold interests
Estimated remaining amortization expense
Total												$ 2,166
Favorable leasehold interests | Minimum
Intangible assets acquired
Amortization Period												2 years
Favorable leasehold interests | Maximum
Intangible assets acquired
Amortization Period												5 years
GDSO
Liabilities assumed:
Goodwill							$ 32,326				32,326	$ 313,617	32,326
Warren Equities Inc
Acquisitions
Percentage of outstanding membership interests acquired			100.00%
Number of convenience stores | store			147
Number of commission agent locations acquired | location			53
Number of dealers with fuel supply rights acquired | item			330
Purchase price			$ 381,800
Number of common units sold | shares												3,565,000
Assets purchased:
Accounts receivable			9,511
Inventory			19,144
Prepaid expenses and other current assets			11,038
Property and equipment			255,148
Intangibles			38,360
Other non-current assets			16,595
Total identifiable assets purchased			349,796
Liabilities assumed:
Accounts payable			(23,067)
Environmental liabilities			(36,467)
Taxes payable			(5,168)
Accrued expenses			(4,462)
Long-term deferred taxes			(75,501)
Other non-current liabilities			(9,739)
Total liabilities assumed			(154,404)
Net identifiable assets acquired			195,392
Goodwill			186,437
Net assets acquired			381,829
Acquired receivables
Receivable fair value			25,000
Receivable amount			29,100
Uncollectible amount			2,400
Acquisition related costs
Acquisition related costs incurred									$ 1,000	$ 4,400	$ 1,700
Warren Equities Inc | Supply Contracts
Assets purchased:
Intangibles			$ 37,600
Intangible assets acquired
Weighted average life			10 years
Contract term before renewal			5 years
Amortization expense												$ 3,900
Estimated remaining amortization expense
2016												3,899
2017												3,899
2018												3,899
2019												3,899
2020												3,899
Thereafter												13,931
Total												33,426
Warren Equities Inc | Supply Contracts | Minimum
Intangible assets acquired
Amortization Period			7 years
Warren Equities Inc | Supply Contracts | Maximum
Intangible assets acquired
Amortization Period			10 years
Warren Equities Inc | Favorable leasehold interests
Assets purchased:
Intangibles			$ 800
Intangible assets acquired
Amortization Period			5 years
Weighted average life			5 years
Estimated remaining amortization expense
2016												152
2017												152
2018												152
2019												152
Total												608
Warren Equities Inc | Accounts Payable [Member]
Acquired receivables
Estimated tax refund payable to selling shareholder												8,300
Assumed liability for tax benefit of net operating losses												1,800
Warren Equities Inc | Accounts Receivable [Member]
Acquired receivables
Estimated tax refund receivable												8,300
Warren Equities Inc | Selling, general and administrative expenses
Acquisition related costs
Acquisition related costs incurred												5,400	$ 1,700
Restructuring Charges						$ 2,300
Revere terminal
Acquisitions
Purchase price		$ 23,700
Assets purchased:
Property and equipment												28,481
Total identifiable assets purchased												28,481
Liabilities assumed:
Environmental liabilities												(3,074)
Liability for contingent consideration												0
Other non-current liabilities												(1,757)
Total liabilities assumed												(4,831)
Net identifiable assets acquired												$ 23,650
Contingent consideration period		8 years
Capitol Petroleum Group
Acquisitions
Number of dealers with fuel supply rights acquired | item	7
Number of owned, leased and/or supplied gasoline stations | location	97
Purchase price	$ 155,700
Assets purchased:
Inventory	346
Property and equipment	149,583
Intangibles	3,000
Other non-current assets	57
Total identifiable assets purchased	152,986
Liabilities assumed:
Environmental liabilities	(300)
Financing obligations	(89,613)
Other non-current liabilities	(2,236)
Total liabilities assumed	(92,149)
Net identifiable assets acquired	60,837
Goodwill	94,854
Net assets acquired	155,691
Acquired receivables
Owned property and equipment	$ 60,000
Sale Leaseback Transaction, Net Book Value [Abstract]
Number of Agreements | item	2											2
Sale Leaseback Transaction, Historical Cost	$ 89,600
Depreciation expense for sale-leaseback properties												$ 2,100
Interest expense for sale-leaseback properties												5,600
Lease rental payments												5,400
Financing obligation	89,600											89,800
Acquisition related costs
Acquisition related costs incurred								$ 100	$ 3,100
Capitol Petroleum Group | Supply Contracts
Assets purchased:
Intangibles	$ 800
Intangible assets acquired
Amortization Period	7 years
Weighted average life	7 years
Contract term before renewal	1 year
Estimated remaining amortization expense
2016												114
2017												114
2018												114
2019												114
2020												114
Thereafter												163
Total												733
Capitol Petroleum Group | Favorable leasehold interests
Assets purchased:
Intangibles	$ 2,200
Intangible assets acquired
Amortization Period	2 years
Weighted average life	2 years
Amortization expense												600
Estimated remaining amortization expense
2016												1,100
2017												458
Total												1,558
Capitol Petroleum Group | Selling, general and administrative expenses
Acquisition related costs
Acquisition related costs incurred												$ 3,500

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Business Combinations - ProForma (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Supplemental Pro-Forma Information
Sales	$ 10,540,275	$ 19,303,900
Net income attributable to Global Partners LP	$ 47,555	$ 85,058
Net income per limited partner unit, basic	$ 1.24	$ 2.89
Net income per limited partner unit, diluted	$ 1.23	$ 2.88
Warren Equities Inc
Supplemental Pro-Forma Information
Amount of sales of acquiree included in consolidated operating results since acquisition date	$ 1,100
Amount of net income (loss) of acquiree included in consolidated operating results since acquisition date	23,000
Capitol Petroleum Group
Supplemental Pro-Forma Information
Amount of sales of acquiree included in consolidated operating results since acquisition date	200
Amount of net income (loss) of acquiree included in consolidated operating results since acquisition date	$ 6,200

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Business Combinations - Prior Acquisitions (Details)	Dec. 31, 2013	Feb. 28, 2013	Feb. 15, 2013	Feb. 01, 2013
Basin Transload LLC
Acquisitions
Percentage of outstanding membership interests acquired	60.00%	60.00%		60.00%
Cascade Kelly
Acquisitions
Percentage of outstanding membership interests acquired			100.00%

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Derivative Financial Instruments (Details) - Dec. 31, 2015 item in Thousands, CAD in Millions, $ in Millions	CAD item	USD ($) item
Exchange-Traded Derivatives | Long [Member]
Volume of activity related to derivative financial instruments
Nonmonetary units	37,785	37,785
Exchange-Traded Derivatives | Short [Member]
Volume of activity related to derivative financial instruments
Nonmonetary units	44,135	44,135
OTC Derivatives (Petroleum/Ethanol) | Long [Member]
Volume of activity related to derivative financial instruments
Nonmonetary units	7,840	7,840
OTC Derivatives (Petroleum/Ethanol) | Short [Member]
Volume of activity related to derivative financial instruments
Nonmonetary units	8,073	8,073
OTC Derivatives (Natural Gas) | Long [Member]
Volume of activity related to derivative financial instruments
Nonmonetary units	9,919	9,919
OTC Derivatives (Natural Gas) | Short [Member]
Volume of activity related to derivative financial instruments
Nonmonetary units	9,939	9,939
Interest rate swaps
Volume of activity related to derivative financial instruments
Monetary units | $		$ 200.0
Interest rate cap
Volume of activity related to derivative financial instruments
Monetary units | $		100.0
Forward foreign currency contracts
Volume of activity related to derivative financial instruments
Monetary units	CAD 0.7	$ 0.5
Forward rate of CAD to USD	1.3828	1.3828

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Derivative Financial Instruments - FV Hedges (Details) - Fair Value Hedge - Cost of sales - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Futures contracts
Fair values of derivative financial instruments
Amount of Gain (Loss) Recognized in Income on Derivatives	$ 151,344	$ 139,473	$ (18,231)
Inventories
Fair values of derivative financial instruments
Amount of Gain (Loss) Recognized in Income on Hedged Items	$ (158,987)	$ (141,699)	$ 17,949

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Derivative Financial Instruments - CF Hedges (Details) $ in Thousands	Dec. 31, 2015 USD ($) item	Dec. 31, 2014 USD ($)	Jun. 19, 2014 USD ($)	Sep. 30, 2013 USD ($)	Apr. 30, 2011 USD ($)	Oct. 31, 2009 USD ($)
Senior Notes 6.25 Percent Due 2022
Fair values of derivative financial instruments
Aggregate principal amount	$ 375,000	$ 375,000	$ 375,000
Cash Flow Hedges
Fair values of derivative financial instruments
Hedged borrowings	200,000
Cash Flow Hedges | Working Capital Facility [Member] | London Interbank Offered Rate (LIBOR) [Member]
Fair values of derivative financial instruments
Hedged borrowings	$ 300,000
Cash Flow Hedges | Interest rate swaps
Fair values of derivative financial instruments
Number of agreements in place | item	2
Cash Flow Hedges | Interest rate swaps | Credit Agreement Maturing 2018 [Member]
Fair values of derivative financial instruments
Fixed rate (as a percent)				1.819%		3.93%
Cash Flow Hedges | Interest rate swaps | Credit Agreement Maturing 2018 [Member] | London Interbank Offered Rate (LIBOR) [Member]
Fair values of derivative financial instruments
Hedged borrowings				$ 100,000		$ 100,000
Cash Flow Hedges | Interest rate cap | Credit Agreement Maturing 2018 [Member]
Fair values of derivative financial instruments
Maximum cap rate (as a percent)					5.50%
Cash Flow Hedges | Interest rate cap | Credit Agreement Maturing 2018 [Member] | London Interbank Offered Rate (LIBOR) [Member]
Fair values of derivative financial instruments
Hedged borrowings					$ 100,000

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Derivative Financial Instruments - CF Hedges Gain, Loss (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Gains and losses from derivatives
Remaining unamortized prepaid interest rate caplets	$ 300,000.00000
Gain (Loss) on Interest Rate Cash Flow Hedge Ineffectiveness	0	$ 0	$ 0
Cash Flow Hedges
Gains and losses from derivatives
Amount of Gain (Loss) Recognized in Other Comprehensive Income on Derivatives	3,336,000	2,758,000	3,930,000
Cash Flow Hedges | Interest rate collar
Gains and losses from derivatives
Amount of Gain (Loss) Recognized in Other Comprehensive Income on Derivatives			1,868,000
Cash Flow Hedges | Interest rate swaps
Gains and losses from derivatives
Amount of Gain (Loss) Recognized in Other Comprehensive Income on Derivatives	3,353,000	2,766,000	2,071,000
Cash Flow Hedges | Interest rate cap
Gains and losses from derivatives
Amount of Gain (Loss) Recognized in Other Comprehensive Income on Derivatives	$ (17,000)	$ (8,000)	$ (9,000)

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Derivative Financial Instruments - Not Designated (Details) - Derivatives not designated as hedging instruments - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Derivative Financial Instruments
Amount of Gain (Loss) Recognized in Income on Derivatives	$ 6,121	$ 18,919	$ 11,657
Commodity product | Cost of sales
Derivative Financial Instruments
Amount of Gain (Loss) Recognized in Income on Derivatives	5,930	18,894	11,819
Foreign currency derivatives | Cost of sales
Derivative Financial Instruments
Amount of Gain (Loss) Recognized in Income on Derivatives	$ 191	$ 25	$ (162)

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Derivative Financial Instruments - Fair Value (Details) $ in Thousands	Dec. 31, 2015 USD ($) item	Dec. 31, 2014 USD ($)
Fair values of derivative financial instruments
Asset Derivatives	$ 161,476	$ 205,342
Liability Derivatives	$ 35,254	65,203
Credit Risk
Number of clearing brokers, primarily utilized | item	3
Exchange-Traded Derivatives | Broker margin deposits
Fair values of derivative financial instruments
Asset Derivatives	$ 95,367	121,490
Forward derivative contracts | Derivative assets
Fair values of derivative financial instruments
Asset Derivatives	66,099	83,826
Forward derivative contracts | Derivative liabilities
Fair values of derivative financial instruments
Liability Derivatives	31,911	58,507
Forward foreign currency contracts | Other assets
Fair values of derivative financial instruments
Asset Derivatives	10	9
Interest rate cap | Other assets
Fair values of derivative financial instruments
Asset Derivatives		17
Interest rate swaps | Other long-term liabilities
Fair values of derivative financial instruments
Liability Derivatives	3,343	6,696
Derivatives designated as hedging instruments
Fair values of derivative financial instruments
Asset Derivatives	83,645	30,600
Derivatives designated as hedging instruments | Exchange-Traded Derivatives | Broker margin deposits
Fair values of derivative financial instruments
Asset Derivatives	83,645	30,600
Derivatives not designated as hedging instruments
Fair values of derivative financial instruments
Asset Derivatives	77,831	174,742
Liability Derivatives	35,254	65,203
Derivatives not designated as hedging instruments | Exchange-Traded Derivatives | Broker margin deposits
Fair values of derivative financial instruments
Asset Derivatives	11,722	90,890
Derivatives not designated as hedging instruments | Forward derivative contracts | Derivative assets
Fair values of derivative financial instruments
Asset Derivatives	66,099	83,826
Derivatives not designated as hedging instruments | Forward derivative contracts | Derivative liabilities
Fair values of derivative financial instruments
Liability Derivatives	31,911	58,507
Derivatives not designated as hedging instruments | Forward foreign currency contracts | Other assets
Fair values of derivative financial instruments
Asset Derivatives	10	9
Derivatives not designated as hedging instruments | Interest rate cap | Other assets
Fair values of derivative financial instruments
Asset Derivatives		17
Derivatives not designated as hedging instruments | Interest rate swaps | Other long-term liabilities
Fair values of derivative financial instruments
Liability Derivatives	$ 3,343	$ 6,696

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Income Taxes (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Reconciliation between the statutory federal income tax rate and the effective income tax rate
Federal statutory income tax rate (as a percent)	35.00%	34.00%	34.00%
State income tax rate, net of federal tax benefit (as a percent)	0.70%	0.70%	0.90%
Foreign income tax rate (as a percent)	0.60%	0.10%
Partnership income not subject to tax (as a percent)	(40.80%)	(34.00%)	(32.90%)
Effective income tax rate (as a percent)	(4.50%)	0.80%	2.00%
Current:
Federal	$ 110	$ (91)	$ (59)
State	1,388	877	542
Foreign	253	188
Total current	1,751	974	483
Deferred:
Federal	(1,298)	948	442
State	(2,326)	(959)	(106)
Total deferred	(3,624)	(11)	336
Income Tax Expense (Benefit), Total	$ (1,873)	$ 963	$ 819

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Income Taxes - Deferred taxes (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Deferred Income Tax Assets
Accounts receivable allowances	$ 2,097	$ 413
Environmental liability	17,814	4,211
Asset retirement obligation	3,132	1,490
Intangible assets, Long-Term		114
Deferred rent	40
UNICAP, Current	747	663
Other	4,477	44
Federal net operating loss carryforwards	13,930	14,203
State net operating loss carryforwards	2,684	1,537
Federal tax credit carryforward	761	13
Total deferred tax assets, Long-Term	45,682	22,688
Valuation allowance, noncurrent	(975)
Total deferred tax assets, net	44,707	22,688
Deferred Income Tax Liabilities
Property and equipment, Long-Term	(104,798)	(30,041)
Land	(11,527)	(5,605)
Intangible assets	13,218
Total deferred tax liabilities	(129,543)	(35,646)
Net deferred tax assets (liabilities)	$ (84,836)	$ (12,958)

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Income Taxes - NOLs (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Operating loss carryforwards
Deferred tax liabilities relating to property and equipment, net operating loss and tax credit carryforwards and other temporary differences	$ 73,300
Increase in valuation allowance for state net operating loss carryforwards	1,000
Reconciliation of differences between income before income tax expense and income subject to income tax expense
Income before income tax expense	41,391	$ 117,943	$ 41,872
Non-taxable income	(48,861)	(117,465)	(41,640)
Income subject to income tax expense	(7,470)	478	232
Income tax paid
Income tax payments during the period	2,772	757	$ 273
Unrecognized tax benefits	100	$ 0
Federal
Operating loss carryforwards
Net operating loss carryforwards	38,500
State
Operating loss carryforwards
Net operating loss carryforwards	$ 54,600

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Property and Equipment (Details) - USD ($) $ in Thousands	3 Months Ended			12 Months Ended
	Dec. 31, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Property and Equipment
Total property and equipment	$ 1,056,327			$ 1,569,840	$ 1,056,327
Less accumulated depreciation	231,276			327,157	231,276
Total	825,051			1,242,683	825,051
Increase in gross total property and equipment				417,600
Acquired property and equipment				433,200
Loss (gain) on sale and disposition of assets	(1,100)	$ (400)	$ (700)	2,097	2,182	$ (1,273)
Property and Equipment [Member]
Property and Equipment
Assets held for sale	3,300			7,400	3,300
Gain Loss on Sale of Property Plant Equipment [Member]
Property and Equipment
Loss (gain) on sale and disposition of assets				(2,100)	(2,200)	1,300
Cost of sales
Property and Equipment
Depreciation expense allocated				94,800	61,400	55,600
Selling, general and administrative expenses
Property and Equipment
Depreciation expense allocated				7,500	6,100	$ 2,300
Buildings, docks, terminal facilities and improvements
Property and Equipment
Total property and equipment	667,172			992,917	667,172
Land
Property and Equipment
Total property and equipment	288,929			450,045	288,929
Fixtures and equipment
Property and Equipment
Total property and equipment	26,577			40,946	26,577
Construction in process
Property and Equipment
Total property and equipment	66,119			67,080	66,119
Construction in process | Crude Oil Activities [ Member ]
Property and Equipment
Total property and equipment	30,800			23,100	30,800
Construction in process | Gas Stations [ Member ]
Property and Equipment
Total property and equipment	4,800			13,500	4,800
Construction in process | Cascade Kelly | Ethanol plants
Property and Equipment
Total property and equipment	30,500			30,500	30,500
Capitalized internal use software
Property and Equipment
Total property and equipment	$ 7,530			$ 18,852	$ 7,530

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Goodwill and Intangible Assets (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Goodwill
Changes to goodwill		$ 0
Roll forward of the Partnership's goodwill
Goodwill, Beginning Balance	$ 154,078
Goodwill, Ending Balance	435,369	154,078
Wholesale Segment
Roll forward of the Partnership's goodwill
Goodwill, Beginning Balance	121,752
Goodwill, Ending Balance	121,752	121,752
GDSO
Roll forward of the Partnership's goodwill
Goodwill, Beginning Balance	32,326
Goodwill, Ending Balance	313,617	$ 32,326
Warren Equities Inc
Roll forward of the Partnership's goodwill
Acquisition	186,437
Warren Equities Inc | GDSO
Roll forward of the Partnership's goodwill
Acquisition	186,437
Capitol Petroleum Group
Roll forward of the Partnership's goodwill
Acquisition	94,854
Capitol Petroleum Group | GDSO
Roll forward of the Partnership's goodwill
Acquisition	$ 94,854

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Goodwill and Intangible Assets - Intangibles (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Intangible Assets
Gross carrying amount of intangible assets subject to amortization	$ 155,694	$ 114,609
Accumulated Amortization	(80,000)	(65,707)
Total	$ 75,694	48,902
Minimum
Intangible Assets
Amortization Period	2 years
Maximum
Intangible Assets
Amortization Period	20 years
Terminalling services
Intangible Assets
Gross carrying amount of intangible assets subject to amortization	$ 26,365	26,365
Accumulated Amortization	(11,087)	(9,752)
Total	$ 15,278	$ 16,613
Amortization Period	20 years	20 years
Customer relationships
Intangible Assets
Gross carrying amount of intangible assets subject to amortization	$ 43,986	$ 43,986
Accumulated Amortization	(39,691)	(35,996)
Total	$ 4,295	$ 7,990
Customer relationships | Minimum
Intangible Assets
Amortization Period	2 years	2 years
Customer relationships | Maximum
Intangible Assets
Amortization Period	15 years	15 years
Supply contracts
Intangible Assets
Gross carrying amount of intangible assets subject to amortization	$ 77,771	$ 39,646
Accumulated Amortization	(24,412)	(16,345)
Total	$ 53,359	$ 23,301
Supply contracts | Minimum
Intangible Assets
Amortization Period	5 years	5 years
Supply contracts | Maximum
Intangible Assets
Amortization Period	15 years	15 years
Favorable leasehold interests
Intangible Assets
Gross carrying amount of intangible assets subject to amortization	$ 2,960
Accumulated Amortization	(794)
Total	$ 2,166
Favorable leasehold interests | Minimum
Intangible Assets
Amortization Period	2 years
Favorable leasehold interests | Maximum
Intangible Assets
Amortization Period	5 years
Brand incentive program
Intangible Assets
Gross carrying amount of intangible assets subject to amortization	$ 1,445	$ 1,445
Accumulated Amortization	(1,117)	(879)
Total	$ 328	$ 566
Amortization Period	5 years	5 years
Software
Intangible Assets
Gross carrying amount of intangible assets subject to amortization	$ 1,139	$ 1,139
Accumulated Amortization	$ (1,139)	$ (1,139)
Amortization Period	5 years	5 years
Covenants not to compete
Intangible Assets
Gross carrying amount of intangible assets subject to amortization	$ 942	$ 942
Accumulated Amortization	$ (942)	$ (942)
Covenants not to compete | Minimum
Intangible Assets
Amortization Period	3 years	3 years
Covenants not to compete | Maximum
Intangible Assets
Amortization Period	5 years	5 years
Customer contracts
Intangible Assets
Gross carrying amount of intangible assets subject to amortization	$ 307	$ 307
Accumulated Amortization	$ (307)	$ (307)
Amortization Period	2 years	2 years
Other intangible assets
Intangible Assets
Gross carrying amount of intangible assets subject to amortization	$ 779	$ 779
Accumulated Amortization	(511)	(347)
Total	$ 268	$ 432
Amortization Period	20 years	20 years

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Goodwill and Intangible Assets - Amortization (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Goodwill and Intangible Assets
Aggregate amortization expense	$ 13,499	$ 18,867	$ 19,216
Estimated annual intangible asset amortization expense
2016	11,011
2017	10,025
2018	9,477
2019	9,477
2020	9,176
Thereafter	26,528
Total	$ 75,694	$ 48,902

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Debt (Details)						12 Months Ended
	Feb. 24, 2016 USD ($)	Jun. 04, 2015 USD ($)	Jun. 01, 2015 USD ($) item	Apr. 21, 2015	Jun. 24, 2014 USD ($)	Dec. 31, 2015 USD ($) DerivativeInstrument item	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)	Jun. 30, 2016	Mar. 31, 2016	Jun. 19, 2014 USD ($)
Debt
Current portion							$ 700,000
Stated interest rate (as a percent)							6.25%
Financing obligation						$ 89,790,000
Number of locations acquired | item			53
Deferred financing fees capitalized						19,000,000	$ 24,000,000
Amortization expenses						5,899,000	5,627,000	$ 6,897,000
Working Capital Facility [Member]
Debt
Total available commitments	$ 900,000,000
Average balance during the period						234,100,000	208,400,000
Line of Credit Facility Estimated Borrowings in Next Year						150,000,000
Long-term portion						150,000,000	100,000,000
Current portion						98,100,000	0
Increased credit facility						148,100,000
Revolving Credit Facility [Member]
Debt
Total available commitments	575,000,000
Average balance during the period						382,200,000	353,200,000
Capitol Petroleum Group
Debt
Financing obligation			$ 89,600,000			$ 89,800,000
Number of sale-leaseback transactions | item			2			2
Sale Leaseback Transaction, Rent Expense						$ 5,400,000
Interest Expense, Lessee, Assets under Capital Lease						5,600,000
Long-Term Debt Caption [Member]
Debt
Unamortized financing fees						7,800,000	8,000,000
Interest Expense [Member]
Debt
Amortization expenses						5,900,000	$ 5,600,000	$ 6,900,000
Credit Agreement Maturing 2018 [Member]
Debt
Total available commitments	1,475,000,000					$ 1,775,000,000
Average interest rates (as a percent)						3.60%	3.70%	4.20%
Number of interest rate swaps | DerivativeInstrument						2
Total borrowings outstanding						$ 517,100,000
Total remaining availability for borrowings and letters of credit						1,200,000	$ 1,400,000
Credit Agreement Maturing 2018 [Member] | All Revolving credit facilities
Debt
Total available commitments						$ 1,775,000,000
Number of line of credit facilities | item						2
Credit Agreement Maturing 2018 [Member] | Working Capital Facility [Member]
Debt
Total available commitments						$ 1,000,000,000
Credit Agreement Maturing 2018 [Member] | Revolving Credit Facility [Member]
Debt
Total available commitments						775,000,000
Total borrowings outstanding						269,000,000
Credit Agreement Maturing 2018 [Member] | Letter of credit
Debt
Outstanding letters of credit						63,700,000
Credit Agreement Maturing 2018 [Member] | Credit Facility Accordion Feature [Member]
Debt
Total available commitments						300,000,000
Credit Agreement Maturing 2018 [Member] | Swing Line Loans [ Member ]
Debt
Total available commitments						50,000,000
Credit Agreement Maturing 2018 [Member] | Other Assets, Current and Noncurrent [Member]
Debt
Unamortized financing fees						11,200,000	16,000,000
Credit Agreement Maturing 2018 [Member] | AR Buyer
Debt
Servicing obligation						0
Senior Notes 6.25 Percent Due 2022
Debt
Aggregate principal amount						$ 375,000,000	$ 375,000,000				$ 375,000,000
Stated interest rate (as a percent)						6.25%	6.25%				6.25%
Minimum percentage of principal amount held by trustee or the holders to declare notes due and payable					25.00%
Indebtedness unpaid or accelerated debt triggering debt default					$ 15,000,000
Period for payment of default					60 days
Percentage Of Senior Notes Exchanged To SEC Registered Notes				100.00%
Senior Notes 7.00 Percent Due 2023 [Member]
Debt
Aggregate principal amount			$ 300,000,000			$ 300,000,000
Stated interest rate (as a percent)		7.00%				7.00%
Minimum percentage of principal amount held by trustee or the holders to declare notes due and payable		25.00%
Percentage of principal amount that the Partnership may redeem		35.00%
Indebtedness unpaid or accelerated debt triggering debt default		$ 50,000,000
Period for payment of default		60 days
Basin Transload Revolving Line of Credit Facility [Member] | All Revolving credit facilities
Debt
Total available commitments						$ 10,000,000
Total borrowings outstanding						$ 0	$ 700,000
Maximum | Credit Agreement Maturing 2018 [Member]
Debt
Commitment fee on the unused portion (as a percent)						0.50%
Asset dispositions permitted	$ 150,000,000					$ 100,000,000
Total Combined Leverage Ratio									5.00	5.50
Minimum | Credit Agreement Maturing 2018 [Member]
Debt
Commitment fee on the unused portion (as a percent)						0.375%
Eurocurrency/Eurodollar rate | Maximum | Credit Agreement Maturing 2018 [Member] | Working Capital Facility [Member]
Debt
Interest rate margin (as a percent)						2.50%
Eurocurrency/Eurodollar rate | Maximum | Credit Agreement Maturing 2018 [Member] | Revolving Credit Facility [Member]
Debt
Interest rate margin (as a percent)						3.25%
Eurocurrency/Eurodollar rate | Minimum | Credit Agreement Maturing 2018 [Member] | Working Capital Facility [Member]
Debt
Interest rate margin (as a percent)						2.00%
Eurocurrency/Eurodollar rate | Minimum | Credit Agreement Maturing 2018 [Member] | Revolving Credit Facility [Member]
Debt
Interest rate margin (as a percent)						2.25%
Cost of funds rate | Maximum | Credit Agreement Maturing 2018 [Member] | Working Capital Facility [Member]
Debt
Interest rate margin (as a percent)						2.50%
Cost of funds rate | Maximum | Credit Agreement Maturing 2018 [Member] | Revolving Credit Facility [Member]
Debt
Interest rate margin (as a percent)						3.25%
Cost of funds rate | Minimum | Credit Agreement Maturing 2018 [Member] | Working Capital Facility [Member]
Debt
Interest rate margin (as a percent)						2.00%
Cost of funds rate | Minimum | Credit Agreement Maturing 2018 [Member] | Revolving Credit Facility [Member]
Debt
Interest rate margin (as a percent)						2.25%
Base rate | Maximum | Credit Agreement Maturing 2018 [Member] | Working Capital Facility [Member]
Debt
Interest rate margin (as a percent)						1.50%
Base rate | Maximum | Credit Agreement Maturing 2018 [Member] | Revolving Credit Facility [Member]
Debt
Interest rate margin (as a percent)						2.25%
Base rate | Minimum | Credit Agreement Maturing 2018 [Member] | Working Capital Facility [Member]
Debt
Interest rate margin (as a percent)						1.00%
Base rate | Minimum | Credit Agreement Maturing 2018 [Member] | Revolving Credit Facility [Member]
Debt
Interest rate margin (as a percent)						1.25%
Debt Instrument, Redemption, Period One [Member] | Senior Notes 6.25 Percent Due 2022
Debt
Percentage of principal amount that the Partnership may redeem					35.00%
Redemption price as a percentage of principal amount					106.25%
Debt Instrument, Redemption, Period One [Member] | Senior Notes 7.00 Percent Due 2023 [Member]
Debt
Redemption price as a percentage of principal amount		107.00%
Debt Instrument, Redemption, Period Two [Member] | Senior Notes 6.25 Percent Due 2022
Debt
Redemption price as a percentage of principal amount					104.688%
Debt Instrument, Redemption, Period Two [Member] | Senior Notes 7.00 Percent Due 2023 [Member]
Debt
Redemption price as a percentage of principal amount		105.25%
Debt Instrument, Redemption, Period Three [Member] | Senior Notes 6.25 Percent Due 2022
Debt
Redemption price as a percentage of principal amount					103.125%
Debt Instrument, Redemption, Period Three [Member] | Senior Notes 7.00 Percent Due 2023 [Member]
Debt
Redemption price as a percentage of principal amount		103.50%
Debt Instrument, Redemption, Period Four [Member] | Senior Notes 6.25 Percent Due 2022
Debt
Redemption price as a percentage of principal amount					101.563%
Debt Instrument, Redemption, Period Four [Member] | Senior Notes 7.00 Percent Due 2023 [Member]
Debt
Redemption price as a percentage of principal amount		101.75%
Debt Instrument, Redemption, Period Five [Member] | Senior Notes 6.25 Percent Due 2022
Debt
Redemption price as a percentage of principal amount					100.00%
Debt Instrument, Redemption, Period Five [Member] | Senior Notes 7.00 Percent Due 2023 [Member]
Debt
Redemption price as a percentage of principal amount		100.00%

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Environmental Liabilities, Asset Retirement Obligations and Renewable Identification Numbers (Details) $ in Thousands		1 Months Ended	12 Months Ended
	Jun. 02, 2010 USD ($) item	Dec. 31, 2012 USD ($) item	Dec. 31, 2015 USD ($)	Dec. 31, 2015 USD ($)	Jun. 30, 2015 USD ($)	Jan. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)	Mar. 31, 2012 USD ($)	Sep. 30, 2010 USD ($)
Changes in environmental liabilities during the period
Balance at the beginning of the period			$ 37,563
Additions			39,841
Payments			(3,598)
Dispositions			(75)
Other Adjustments			(498)
Balance at the end of the period			73,233
Environmental liabilities
Current portion				$ 5,350			$ 3,101
Long-term portion				67,883			34,462
Total environmental liabilities			$ 37,563	73,233			37,563
Renewable Identification Numbers (RINs)
Settlement period of RVO			1 year
RIN Deficiency				400			300
Retail Gasoline Stations
Changes in environmental liabilities during the period
Balance at the beginning of the period			$ 35,792
Additions			36,767
Payments			(3,535)
Dispositions			(75)
Other Adjustments			(498)
Balance at the end of the period			68,451
Environmental liabilities
Total environmental liabilities			35,792	68,451			35,792
Mutual Oil Gasoline Stations
Environmental Liabilities
Assumed environmental liabilities, recorded on an undiscounted basis		$ 600
Number of gasoline stations acquired | item		6
Alliance Gasoline Stations
Environmental Liabilities
Assumed environmental liabilities, recorded on an undiscounted basis								$ 16,100
ExxonMobil Gasoline Stations
Environmental Liabilities
Assumed environmental liabilities, recorded on an undiscounted basis					$ 300				$ 30,000
Terminals
Changes in environmental liabilities during the period
Balance at the beginning of the period			1,771
Additions			3,074
Payments			(63)
Balance at the end of the period			4,782
Environmental liabilities
Total environmental liabilities			$ 1,771	$ 4,782			$ 1,771
Terminals in Newburgh New York
Environmental Liabilities
Assumed environmental liabilities, recorded on an undiscounted basis	$ 1,500
Number of refined petroleum products terminals acquired | item	3
Revere terminal
Environmental Liabilities
Assumed environmental liabilities, recorded on an undiscounted basis						$ 3,100
Warren Equities Inc | Retail Gasoline Stations
Environmental Liabilities
Assumed environmental liabilities, recorded on an undiscounted basis						$ 36,500

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Trustee Taxes and Accrued Expenses and Other Current Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Trustee Taxes and Accrued Expenses and Other Current Liabilities
Barging transportation, product storage and other ancillary cost accruals	$ 13,385	$ 19,843
Employee compensation	16,098	26,827
Accrued interest	12,524	12,839
Customer Advance		12,000
RIN and RVO Deficiency	367	253
Other	17,954	11,058
Total	60,328	82,820
Taxes payable
Trustee taxes payable	95,264	105,744
Trustee taxes payable related to an ethanol credit	55,400	55,400
Various pass-through taxes collected from customers on behalf of taxing authorities	$ 39,900	$ 50,300

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Employee Benefit Plans with Related Party (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Employee Benefit Plans with Related Party
Maximum percent of discretionary non-matching contributions by General Partner	2.00%
Global 401(k) Plan and the GMG 401(k) Plan
Employee Benefit Plans with Related Party
Expenses of the plan included in selling, general and administrative expenses	$ 2.4	$ 2.0	$ 1.8
Global 401(k) Plan
Employee Benefit Plans with Related Party
Maximum employee contribution as a percent of compensation	100.00%
Employee contribution subject to employer match, first level (as a percent)	100.00%
Employer contribution subject to employer match, second level (as a percent)	50.00%
Global 401(k) Plan | Minimum
Employee Benefit Plans with Related Party
Employer match of second level of employee contribution (as a percent)	3.00%
Global 401(k) Plan | Maximum
Employee Benefit Plans with Related Party
Employer match of first level of employee contribution (as a percent)	3.00%
Employer match of second level of employee contribution (as a percent)	5.00%
GMG 401(k) Plan
Employee Benefit Plans with Related Party
Maximum employee contribution as a percent of compensation	100.00%
Employee contribution subject to employer match, first level (as a percent)	100.00%
Employer contribution subject to employer match, second level (as a percent)	50.00%
GMG 401(k) Plan | Minimum
Employee Benefit Plans with Related Party
Employer match of second level of employee contribution (as a percent)	3.00%
GMG 401(k) Plan | Maximum
Employee Benefit Plans with Related Party
Employer match of first level of employee contribution (as a percent)	3.00%
Employer match of second level of employee contribution (as a percent)	5.00%

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Employee Benefit Plans with Related Party - Pension Plan (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2015 USD ($) item	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)
Employee Benefit Plans with Related Party
Projected benefit obligation	$ 23,615	$ 23,615		$ 20,931	$ 23,615
Fair value of plan assets				16,886	18,023
Net unfunded pension liability				4,045	5,592
Components of net periodic benefit cost
Benefit obligation at beginning of year	23,615
Benefit obligation at end of year	20,931	23,615
Components of estimated future benefit payments
2016				2,001
2017				2,436
2018				833
2019				808
2020				1,334
2021-2025				4,933
Total				12,345
Pension Plans
Employee Benefit Plans with Related Party
Projected benefit obligation	23,615	19,245	$ 23,073	20,932	23,615
Actual return on plan assets	(200)	1,200
Components of net periodic benefit cost
Benefit obligation at beginning of year	23,615	19,245	23,073
Interest cost	801	804	730
Actuarial (gain) loss	(1,925)	5,151	(2,419)
Benefits paid	(1,559)	(1,585)	(2,139)
Benefit obligation at end of year	$ 20,932	23,615	$ 19,245
Global Pension Plan
Employee Benefit Plans with Related Party
Normal retirement age of employees | item	65
Projected benefit obligation	$ 18,333	18,333		16,338	18,333
Fair value of plan assets				13,481	14,545
Net unfunded pension liability				2,857	3,788
Components of net periodic benefit cost
Benefit obligation at beginning of year	18,333
Benefit obligation at end of year	$ 16,338	$ 18,333
Components of weighted-average actuarial assumptions
Discount rate	4.00%	3.60%	4.40%
Expected return on plan assets	7.00%	7.50%	7.50%
Components of estimated future benefit payments
Contributions made by the General Partner, the Partnership and its subsidiaries to the Pension Plans	$ 600	$ 200	$ 500
GMG Pension Plan
Employee Benefit Plans with Related Party
Normal retirement age of employees | item	65
Projected benefit obligation	$ 5,282	5,282		4,593	5,282
Fair value of plan assets				3,405	3,478
Net unfunded pension liability				$ 1,188	$ 1,804
Components of net periodic benefit cost
Benefit obligation at beginning of year	5,282
Benefit obligation at end of year	$ 4,593	$ 5,282
Components of weighted-average actuarial assumptions
Discount rate	4.30%	3.60%	4.40%
Expected return on plan assets	7.00%	7.00%	7.00%

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Long-Term Incentive Plan (Details) - USD ($)	12 Months Ended			80 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2015
Long-Term Incentive Plan
Number of common units initially authorized for issuance under LTIP (in shares)	4,300,000			4,300,000
Phantom units granted (in shares)	76,893	44,902
Vested (in shares)	(13,921)	(10,266)
Compensation cost related to the non-vested awards not yet recognized	$ 14,400,000			$ 14,400,000
Number of Non-vested Units
Outstanding non-vested units at the beginning of the period (in shares)	532,748	498,112
Granted (in shares)	76,893	44,902
Vested (in shares)	(13,921)	(10,266)
Outstanding non-vested units at the end of the period (in shares)	595,720	532,748	498,112	595,720
Weighted Average Grant Date Fair Value
Outstanding non-vested units at the beginning of the period (in dollars per share)	$ 39.29	$ 39.29
Granted (in dollars per share)	35.72	39.34
Vested (in dollars per share)	38.39	39.29
Outstanding non-vested units at the end of the period (in dollars per share)	$ 38.85	$ 39.29	$ 39.29	$ 38.85
Repurchase Program
Aggregate common units authorized to be acquired (in shares)	1,242,427			1,242,427
Common units repurchased by General Partner (in shares)				838,505
Common units repurchased by General Partner	$ 3,892,000	$ 8,632,000	$ 4,590,000	$ 24,800,000
Repurchased units not deemed outstanding	403,922	390,602		403,922
CEO Authorized LTIP
Long-Term Incentive Plan
Number of years for which Plan was approved	3 years
Aggregate amount of CEO authorized shares to grant in each calendar year			$ 2,000,000
Maximum value of grant	$ 550,000
CEO Authorized LTIP expiration period	6 years
Phantom Unit Awards [Member]
Long-Term Incentive Plan
Phantom units granted (in shares)			498,112
Vested (in shares)		(10,266)
Number of Non-vested Units
Granted (in shares)			498,112
Vested (in shares)		(10,266)
Phantom Unit Awards [Member] | Selling, general and administrative expenses
Long-Term Incentive Plan
Compensation expenses for phantom unit awards	$ 4,300,000	$ 3,500,000	$ 1,700,000
Certain Employees | Phantom Unit Awards [Member]
Long-Term Incentive Plan
Phantom units granted (in shares)		44,902
Number of Non-vested Units
Granted (in shares)		44,902

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Commitments and Contingencies (Details) gal in Thousands, $ in Thousands	1 Months Ended	12 Months Ended
	May. 31, 2013 USD ($)	Dec. 31, 2015 USD ($) gal	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)
Minimum volume purchase requirements
2016 | gal		397,600
2017 | gal		331,900
2018 | gal		330,100
2019 | gal		327,700
2020 | gal		312,700
Thereafter | gal		828,300
Total | gal		2,528,300
Purchase commitment
Brand Fee Agreement, future minimum payments
2016		$ 9,000
2017		9,000
2018		9,000
2019		9,000
2020		9,000
Thereafter		40,500
Total		85,500
Brand Fee Agreement
Expenses reflected in cost of sales related to agreement		9,000	$ 9,000	$ 9,000
Office Space and Equipment [Member]
Future minimum payments under leases with non-cancelable terms
2016		2,816
2017		2,743
2018		2,644
2019		2,650
2020		2,297
Thereafter		13,840
Total		26,990
Operating leases rent income (expense)
Expenses under the operating lease arrangements		2,500	2,700	2,700
Annual rental income	$ 200	100
Future minimum rental income under non-cancelable operating leases
Rental income	$ 200	100
Terminal and Throughput Leases
Future minimum payments under leases with non-cancelable terms
2016		14,984
2017		8,353
2018		723
2019		132
Total		24,192
Operating leases rent income (expense)
Expenses under the operating lease arrangements		22,500	31,500	35,500
Gasoline station buildings, improvements and storage tanks
Future minimum payments under leases with non-cancelable terms
2016		29,432
2017		26,102
2018		23,365
2019		20,712
2020		18,236
Thereafter		98,193
Total		216,040
Operating leases rent income (expense)
Expenses under the operating lease arrangements		29,400	19,700	17,700
Gasoline station equipment
Operating leases rent income (expense)
Annual rental income		61,100	42,500	41,300
Future minimum rental income under non-cancelable operating leases
2016		45,125
2017		23,781
2018		7,797
2019		1,212
2020		1,079
Thereafter		17,001
Total		95,995
Aggregate carrying value of the leased gasoline stations and equipment, net		368,400
Accumulated depreciation of the leased gasoline stations and equipment		48,700
Rental income		61,100	42,500	41,300
Railcars
Future minimum payments under leases with non-cancelable terms
2016		59,625
2017		52,186
2018		45,968
2019		28,532
2020		2,257
Thereafter		608
Total		189,176
Operating leases rent income (expense)
Expenses under the operating lease arrangements		57,700	56,900	28,900
Future minimum rental income under non-cancelable operating leases
2016		10,800
2017		2,700
Barges
Future minimum payments under leases with non-cancelable terms
2016		58,256
2017		45,854
2018		36,440
2019		12,223
2020		1,983
Total		154,756
Operating leases rent income (expense)
Expenses under the operating lease arrangements		87,300	60,600	37,100
Land and Equipment | Port of St. Helens Agreements
Future minimum payments under leases with non-cancelable terms
2016		223
2017		223
2018		223
2019		223
2020		223
Thereafter		10,128
Total		11,243
Operating leases rent income (expense)
Expenses under the operating lease arrangements		$ 223	$ 222	$ 180

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Commitments and Contingencies - Other Commitments (Details) $ in Millions	1 Months Ended
	Jun. 30, 2014 USD ($)	May. 31, 2014 USD ($)	Apr. 30, 2014 USD ($) mi	Aug. 31, 2013 USD ($)	Mar. 31, 2013 mi bbl	Dec. 31, 2015 USD ($)
Pipeline Connection Agreement [Member] | Divide County, North Dakota to Columbus, North Dakota [Member]
Other Commitment
Minimum commitment amount	$ 55.0					$ 55.0
Period of minimum take-or-pay throughput commitment	7 years
Pipeline Connection Agreement [Member] | Dunn and McKenzie Counties, North Dakota to Williams County, North Dakota [Member]
Other Commitment
Minimum commitment amount		$ 36.4				31.2
Minimum quarterly commitment amount						1.3
Period of minimum take-or-pay throughput commitment		7 years
Pipeline Connection Agreement [Member] | Mercer Country, North Dakota to Beulah, North Dakota [Member]
Other Commitment
Length of pipeline lateral which would be built, owned and operated | mi			4
Minimum commitment amount			$ 8.7			8.1
Period of minimum take-or-pay throughput commitment			5 years
Pipeline Connection Agreement [Member] | Lignite, North Dakota to Columbus, North Dakota [Member]
Other Commitment
Length of pipeline lateral which would be built, owned and operated | mi					7
Volume of crude oil storage tank (in barrels) | bbl					100,000
Minimum commitment amount				$ 13.0		0.0
Period of minimum take-or-pay throughput commitment				5 years
Natural Gas Transportation and Reservation Agreement [Member]
Other Commitment
Minimum commitment amount						14.3
Pipeline connection agreement with Tesoro Logistics
Other Commitment
Minimum commitment amount						$ 0.0

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Partners' Equity and Cash Distributions (Details) $ / shares in Units, $ in Thousands																				1 Months Ended				3 Months Ended	12 Months Ended
	Feb. 16, 2016 USD ($)	Jan. 28, 2016 $ / shares	Nov. 13, 2015 USD ($) $ / shares	Oct. 21, 2015 $ / shares	Aug. 14, 2015 USD ($) $ / shares	Jul. 22, 2015 $ / shares	Jun. 11, 2015 shares	May. 15, 2015 USD ($) $ / shares	Apr. 22, 2015 $ / shares	Feb. 14, 2015 USD ($) $ / shares	Dec. 05, 2014 shares	Nov. 14, 2014 USD ($) $ / shares	Aug. 14, 2014 USD ($) $ / shares	May. 15, 2014 USD ($) $ / shares	Feb. 14, 2014 USD ($) $ / shares	Nov. 14, 2013 USD ($) $ / shares	Aug. 14, 2013 USD ($) $ / shares	May. 15, 2013 USD ($) $ / shares	Feb. 14, 2013 USD ($) $ / shares	Jun. 30, 2015 shares	May. 31, 2015	Dec. 31, 2014 shares	Nov. 30, 2014	Mar. 31, 2015 shares	Dec. 31, 2015 item $ / shares shares	Dec. 31, 2014 shares
Partners' Equity and Cash Distributions
General partner interest (as a percent)																				0.67%	0.74%	0.74%	0.83%
Limited Partner Units
Beginning balance																								30,604,961	30,604,961
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares																				3,000,000		3,565,000
Increase (Decrease) in Partners' Capital [Roll Forward]
Units, beginning balance																								31,225,866	31,225,866	27,660,866
Public offering of common units											3,565,000													3,000,000		3,565,000
Units, ending balance																						31,225,866		34,225,866		31,225,866
Repurchased units not deemed outstanding																						390,602			403,922	390,602
Period of distribution of available cash after end of each quarter																									45 days
Number of quarters of cash reserves to provide funds for distributions to unitholders and General Partner | item																									4
Cash Distribution Payment
Per Unit Cash Distribution (in dollars per unit) | $ / shares			$ 0.6975		$ 0.6925			$ 0.6800		$ 0.6650		$ 0.6525	$ 0.6375	$ 0.6250	$ 0.6125	$ 0.6000	$ 0.5875	$ 0.5825	$ 0.5700
Cash distribution | $			$ 26,650		$ 26,320			$ 23,260		$ 22,357		$ 19,319	$ 18,772	$ 18,323	$ 17,874	$ 17,425	$ 16,975	$ 16,796	$ 16,346
Distribution declared
Quarterly cash distribution declared (in dollars per unit) | $ / shares				$ 0.6975		$ 0.6925			$ 0.6800
Affiliates of general partner
Partners' Equity and Cash Distributions
Limited partner ownership interest (as a percent)																									21.90%
General partner interest (as a percent)																									21.90%
Subsequent event
Distribution declared
Quarterly cash distribution declared (in dollars per unit) | $ / shares		$ 0.4625
Common Units
Limited Partner Units
Beginning balance																										27,430,563
Increase (Decrease) in Partners' Capital [Roll Forward]
Units, beginning balance																								30,995,563	30,995,563
Public offering of common units																								3,000,000		3,565,000
Units, ending balance																						30,995,563		33,995,563	33,995,563	30,995,563
Repurchased units not deemed outstanding																						390,602			403,922	390,602
Common Units | Affiliates of general partner
Increase (Decrease) in Partners' Capital [Roll Forward]
Units, ending balance																									7,434,775
Common Units | Subsequent event
Cash Distribution Payment
Cash distribution | $	$ 15,800
Distribution declared
Quarterly cash distribution declared (in dollars per unit) | $ / shares		0.4625
Common Units | Subsequent event | Annualized basis
Distribution declared
Quarterly cash distribution declared (in dollars per unit) | $ / shares		$ 1.85
General Partner Interest
Increase (Decrease) in Partners' Capital [Roll Forward]
Units, beginning balance																								230,303	230,303	230,303
Units, ending balance																						230,303		230,303	230,303	230,303
Common Unitholders
Partners' Equity and Cash Distributions
Limited partner ownership interest (as a percent)																				99.26%					99.33%	99.17%
Increase (Decrease) in Partners' Capital [Roll Forward]
Repurchased units not deemed outstanding																						390,602			403,922	390,602
Marginal Percentage Interest in Distributions																									99.33%
Common Unitholders | Common Units
Increase (Decrease) in Partners' Capital [Roll Forward]
Public offering of common units							3,000,000
Cash Distribution Payment
Cash distribution | $			23,713		23,543			21,076		20,612		17,899	17,487	17,145	16,802	16,459	16,116	15,979	15,636
General Partner
Partners' Equity and Cash Distributions
General partner interest (as a percent)																				0.74%					0.67%	0.83%
Increase (Decrease) in Partners' Capital [Roll Forward]
Marginal Percentage Interest in Distributions																									0.67%
Cash Distribution Payment
Incentive Distribution | $			2,777		2,618			2,027		1,591		1,270	1,139	1,035	932	828	724	683	579
General Partner | General Partner Interest
Cash Distribution Payment
Cash distribution | $			$ 160		$ 159			$ 157		$ 154		$ 150	$ 146	$ 143	$ 140	$ 138	$ 135	$ 134	$ 131
First Target Distribution | Maximum
Increase (Decrease) in Partners' Capital [Roll Forward]
Total Quarterly Distribution Target Amount (in dollars per unit) | $ / shares																									$ 0.4625
First Target Distribution | Common Unitholders | Common Units
Increase (Decrease) in Partners' Capital [Roll Forward]
Marginal Percentage Interest in Distributions																									99.33%
First Target Distribution | General Partner | General Partner Interest
Increase (Decrease) in Partners' Capital [Roll Forward]
Marginal Percentage Interest in Distributions																									0.67%
Second Target Distribution | Minimum
Increase (Decrease) in Partners' Capital [Roll Forward]
Total Quarterly Distribution Target Amount (in dollars per unit) | $ / shares																									$ 0.4625
Second Target Distribution | Maximum
Increase (Decrease) in Partners' Capital [Roll Forward]
Total Quarterly Distribution Target Amount (in dollars per unit) | $ / shares																									$ 0.5375
Second Target Distribution | Common Unitholders | Common Units
Increase (Decrease) in Partners' Capital [Roll Forward]
Marginal Percentage Interest in Distributions																									86.33%
Second Target Distribution | General Partner | General Partner Interest
Increase (Decrease) in Partners' Capital [Roll Forward]
Marginal Percentage Interest in Distributions																									13.67%
Third Target Distribution | Minimum
Increase (Decrease) in Partners' Capital [Roll Forward]
Total Quarterly Distribution Target Amount (in dollars per unit) | $ / shares																									$ 0.5375
Third Target Distribution | Maximum
Increase (Decrease) in Partners' Capital [Roll Forward]
Total Quarterly Distribution Target Amount (in dollars per unit) | $ / shares																									$ 0.6625
Third Target Distribution | Common Unitholders | Common Units
Increase (Decrease) in Partners' Capital [Roll Forward]
Marginal Percentage Interest in Distributions																									76.33%
Third Target Distribution | General Partner | General Partner Interest
Increase (Decrease) in Partners' Capital [Roll Forward]
Marginal Percentage Interest in Distributions																									23.67%
Thereafter | Minimum
Increase (Decrease) in Partners' Capital [Roll Forward]
Total Quarterly Distribution Target Amount (in dollars per unit) | $ / shares																									$ 0.6625
Thereafter | Common Unitholders | Common Units
Increase (Decrease) in Partners' Capital [Roll Forward]
Marginal Percentage Interest in Distributions																									51.33%
Thereafter | General Partner | General Partner Interest
Increase (Decrease) in Partners' Capital [Roll Forward]
Marginal Percentage Interest in Distributions																									48.67%

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Unitholders' Equity (Details) - USD ($) $ / shares in Units, $ in Thousands					3 Months Ended	12 Months Ended
	Jun. 11, 2015	May. 19, 2015	Dec. 10, 2014	Dec. 05, 2014	Mar. 31, 2015	Dec. 31, 2015	Dec. 31, 2014
Number of common units sold				3,565,000	3,000,000		3,565,000
Common units issued in public offering, offer price (in dollars per share)				$ 40.24
Net proceeds from public offering after deducting underwriting fees and offering expenses						$ 109,305	$ 137,844
Underwriters' Allotment Option
Net proceeds from public offering after deducting underwriting fees and offering expenses			$ 137,800
Common Units
Number of common units sold					3,000,000		3,565,000
Net proceeds from public offering after deducting underwriting fees and offering expenses	$ 109,300
Common Units | At The Market Offering Program
Number of common units sold						0
Aggregate offering price		$ 50,000
Common Unitholders | Common Units
Number of common units sold	3,000,000
Common units issued in public offering, offer price (in dollars per share)	$ 38.12

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Related-Party Transactions (Details) - USD ($)	6 Months Ended	12 Months Ended
	Jul. 10, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Information on related party transaction
Receivables from related parties		$ 2,578,000	$ 3,903,000
GPC
Information on related party transaction
Receivables from related parties			108,000
GPC | Terminal Storage Rental and Throughput Agreement [Member]
Information on related party transaction
Expenses incurred from transactions with related parties		$ 800,000	9,200,000	$ 9,100,000
GPC | Terminal Storage Rental and Throughput Agreement [Member] | Members of Slifka family
Related Party Transactions
Equity Method Investment, Ownership Percentage		100.00%
GPC | GPC Amended and Restated Services Agreement [Member]
Information on related party transaction
Related party amounts recorded as selling, general and administrative expenses		$ 8,000	96,000	96,000
Notice period to terminate the receipt of services under the agreement		90 days
GPC | Second amended and restated terminal storage rental and throughput agreement
Information on related party transaction
Annual consumer price index adjustments included in expenses		$ 0	1,900,000	1,800,000
AE Holdings | AEH Amended and Restated Services Agreement [Member]
Information on related party transaction
Amount to be received per year	$ 15,000
General Partner
Information on related party transaction
Expenses incurred from transactions with related parties		109,000,000	95,500,000	$ 79,300,000
Receivables from related parties		$ 2,578,000	$ 3,795,000

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Segment Reporting (Details) $ in Thousands, gal in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015 USD ($)	Sep. 30, 2015 USD ($)	Jun. 30, 2015 USD ($)	Mar. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)	Sep. 30, 2014 USD ($)	Jun. 30, 2014 USD ($)	Mar. 31, 2014 USD ($)	Dec. 31, 2015 USD ($) gal	Dec. 31, 2014 USD ($) gal	Dec. 31, 2013 USD ($) gal
Summarized financial information for the Partnership's reportable segments
Sales	$ 2,169,445	$ 2,486,203	$ 2,680,088	$ 2,979,116	$ 3,532,948	$ 4,050,458	$ 4,569,620	$ 5,116,928	$ 10,314,852	$ 17,269,954	$ 19,589,608
Product margin									692,458	606,148	460,209
Gross profit	$ 132,624	$ 152,299	$ 144,188	$ 168,558	$ 142,643	$ 155,435	$ 87,685	$ 159,024	597,669	544,787	404,556
Wholesale Segment
Summarized financial information for the Partnership's reportable segments
Sales									5,911,285	12,896,129	15,205,654
Product margin									207,922	293,054	202,870
Gasoline sales: gasoline and gasoline blendstocks (such as ethanol)
Summarized financial information for the Partnership's reportable segments
Sales									2,714,057	7,076,105	8,085,225
Product margin									66,031	71,713	43,147
Crude Oil
Summarized financial information for the Partnership's reportable segments
Sales									1,190,560	2,384,018	3,561,428
Product margin									74,182	141,965	92,807
Other oils and related products
Summarized financial information for the Partnership's reportable segments
Sales									2,006,668	3,436,006	3,559,001
Product margin									67,709	79,376	66,916
GDSO
Summarized financial information for the Partnership's reportable segments
Sales									3,670,936	3,407,376	3,378,428
Product margin									455,335	283,378	228,980
Gasoline
Summarized financial information for the Partnership's reportable segments
Sales									3,289,742	3,241,620	3,231,925
Product margin									276,848	189,439	150,147
Station operations
Summarized financial information for the Partnership's reportable segments
Sales									381,194	165,756	146,503
Product margin									178,487	93,939	78,833
Commercial Segment
Summarized financial information for the Partnership's reportable segments
Sales									732,631	966,449	1,005,526
Product margin									29,201	29,716	28,359
Operating costs and expenses not allocated to operating segments
Summarized financial information for the Partnership's reportable segments
Depreciation allocated to cost of sales									$ (94,789)	$ (61,361)	$ (55,653)
Intersegment transaction | GDSO
Summarized financial information for the Partnership's reportable segments
Sales volume supplied by Wholesale to GDSO (in gallons) | gal									450.0	450.0	500.0

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Segment Reporting - Risk (Details) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015 USD ($)	Sep. 30, 2015 USD ($)	Jun. 30, 2015 USD ($)	Mar. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)	Sep. 30, 2014 USD ($)	Jun. 30, 2014 USD ($)	Mar. 31, 2014 USD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($) customer	Dec. 31, 2013 USD ($) item
Segment Reporting
Number of Major Customers										1	2
Total revenues	$ 2,169,445	$ 2,486,203	$ 2,680,088	$ 2,979,116	$ 3,532,948	$ 4,050,458	$ 4,569,620	$ 5,116,928	$ 10,314,852	$ 17,269,954	$ 19,589,608
Wholesale Segment
Segment Reporting
Total revenues									$ 5,911,285	12,896,129	15,205,654
Wholesale Segment | Sales | Customer | ExxonMobil
Segment Reporting
Total revenues										$ 2,900,000	$ 2,900,000
Percentage of revenues										17.00%	15.00%
Wholesale Segment | Sales | Customer | Phillips 66
Segment Reporting
Total revenues											$ 2,400,000
Percentage of revenues											12.00%

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Segment Reporting - Reconciliation (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Reconciliation of the totals reported for the reportable segments to the applicable line items in the consolidated financial statements
Combined gross profit	$ 132,624	$ 152,299	$ 144,188	$ 168,558	$ 142,643	$ 155,435	$ 87,685	$ 159,024	$ 597,669	$ 544,787	$ 404,556
Operating costs and expenses
Selling, general and administrative expenses									177,043	153,961	115,491
Operating expenses									290,307	204,070	185,713
Amortization expense									13,499	18,867	19,216
Loss (gain) on sale and disposition of assets					(1,100)		(400)	(700)	2,097	2,182	(1,273)
Total costs and operating expenses									482,946	379,080	319,147
Operating income									114,723	165,707	85,409
Interest expense									(73,332)	(47,764)	(43,537)
Income tax benefit (expense)									1,873	(963)	(819)
Net income	(2,905)	8,146	7,614	30,409	28,482	43,622	(12,278)	57,154	43,264	116,980	41,053
Net income attributable to noncontrolling interest									299	(2,271)	1,562
Net income attributable to Global Partners LP	$ (2,282)	$ 8,212	$ 7,218	$ 30,415	$ 27,910	$ 42,508	$ (12,719)	$ 57,010	43,563	114,709	42,615
Foreign sales											0
Operating costs and expenses not allocated to operating segments
Operating costs and expenses
Selling, general and administrative expenses									177,043	153,961	115,491
Operating expenses									290,307	204,070	185,713
Amortization expense									13,499	18,867	19,216
Loss (gain) on sale and disposition of assets									2,097	2,182	(1,273)
Total costs and operating expenses									$ 482,946	$ 379,080	$ 319,147

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Segment Reporting - Assets (Details) - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Segment assets
Total	$ 2,663,675,000	$ 2,030,817,000
Wholesale Segment
Segment assets
Total	774,352,000	807,708,000
Commercial Segment
Segment assets
Total	3,224,000	3,827,000
GDSO
Segment assets
Total	1,392,397,000	622,860,000
Unallocated
Segment assets
Total	$ 493,702,000	$ 596,422,000

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Fair Value Measurements (Details)	12 Months Ended
	Dec. 31, 2015 USD ($) $ / item	Dec. 31, 2014 USD ($) $ / item	Jun. 04, 2015	Jun. 01, 2015 USD ($)	Jun. 19, 2014 USD ($)
Assets:
Pension plans	$ 16,886,000	$ 18,023,000
Liabilities:
Stated interest rate (as a percent)		6.25%
Senior Notes 6.25 Percent Due 2022
Liabilities:
Stated interest rate (as a percent)	6.25%	6.25%			6.25%
Carrying value of debt instrument	$ 375,000,000	$ 375,000,000			$ 375,000,000
Fair value of debt instrument	$ 307,500,000	358,594,000
Senior Notes 7.00 Percent Due 2023 [Member]
Liabilities:
Stated interest rate (as a percent)	7.00%		7.00%
Carrying value of debt instrument	$ 300,000,000			$ 300,000,000
Fair value of debt instrument	249,000,000
Level 3
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Fair Value, beginning of period	(25,523,000)
Transfers into level 3	516,000
Realized and unrealized gains (losses) recorded in cost of sales	25,071,000
Fair Value, end of period	$ 64,000	$ (25,523,000)
Minimum | Level 3
Liabilities:
Estimated margin, crude oil (in dollars per barrel) | $ / item	4.00
Estimated margin, propane (in dollars per barrel) | $ / item	2.1
Estimates Margin for Transportation and Throughput Costs Per Barrel | $ / item	11.00
Maximum | Level 3
Liabilities:
Estimated margin, crude oil (in dollars per barrel) | $ / item	13.55
Estimated margin, propane (in dollars per barrel) | $ / item	9.66
Estimates Margin for Transportation and Throughput Costs Per Barrel | $ / item		18.00
Recurring basis
Assets:
Pension plans	$ 16,886,000	$ 18,023,000
Cash collateral netting	(64,040,000)	(104,292,000)
Total assets	114,322,000	119,073,000
Liabilities:
Total liabilities	(35,254,000)	(65,203,000)
Recurring basis | Forward derivative contracts
Assets:
Derivative assets	66,099,000	83,826,000
Liabilities:
Derivative liabilities	(31,255,000)	(56,428,000)
Recurring basis | Swap agreements and option contracts
Liabilities:
Derivative liabilities	(656,000)	(2,079,000)
Recurring basis | Foreign currency derivatives
Assets:
Derivative assets	10,000	9,000
Recurring basis | Interest rate cap
Assets:
Derivative assets		17,000
Recurring basis | Interest rate swaps
Liabilities:
Derivative liabilities	(3,343,000)	(6,696,000)
Recurring basis | Exchange-Traded Derivatives
Assets:
Exchange-traded/cleared derivative instruments	31,327,000	17,198,000
Cash collateral netting	(64,040,000)	(104,292,000)
Recurring basis | Level 1
Assets:
Pension plans	16,886,000	18,023,000
Total assets	112,253,000	139,513,000
Recurring basis | Level 1 | Exchange-Traded Derivatives
Assets:
Exchange-traded/cleared derivative instruments	95,367,000	121,490,000
Recurring basis | Level 2
Assets:
Total assets	62,392,000	81,447,000
Liabilities:
Total liabilities	(31,601,000)	(37,275,000)
Recurring basis | Level 2 | Forward derivative contracts
Assets:
Derivative assets	62,382,000	81,421,000
Liabilities:
Derivative liabilities	(27,602,000)	(28,500,000)
Recurring basis | Level 2 | Swap agreements and option contracts
Liabilities:
Derivative liabilities	(656,000)	(2,079,000)
Recurring basis | Level 2 | Foreign currency derivatives
Assets:
Derivative assets	10,000	9,000
Recurring basis | Level 2 | Interest rate cap
Assets:
Derivative assets		17,000
Recurring basis | Level 2 | Interest rate swaps
Liabilities:
Derivative liabilities	(3,343,000)	(6,696,000)
Recurring basis | Level 3
Assets:
Total assets	3,717,000	2,405,000
Liabilities:
Total liabilities	(3,653,000)	(27,928,000)
Recurring basis | Level 3 | Forward derivative contracts
Assets:
Derivative assets	3,717,000	2,405,000
Liabilities:
Derivative liabilities	$ (3,653,000)	$ (27,928,000)

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Changes in Accumulated Other Comprehensive Loss (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Changes in Accumulated Other Comprehensive Loss
Balance at the beginning of the period	$ (13,252)
Total other comprehensive income	5,158
Balance at the end of the period	(8,094)	$ (13,252)
Derivatives
Changes in Accumulated Other Comprehensive Loss
Balance at the beginning of the period	(7,705)	(10,856)
Other comprehensive (loss) income before reclassifications of gain (loss)	4,047	3,151
Total other comprehensive income	4,047	3,151
Balance at the end of the period	(3,658)	(7,705)
Pension Plan
Changes in Accumulated Other Comprehensive Loss
Balance at the beginning of the period	(5,547)	(454)
Other comprehensive (loss) income before reclassifications of gain (loss)	1,192	(4,660)
Amount of gain (loss) reclassified from accumulated other comprehensive (loss) income	(81)	(433)
Total other comprehensive income	1,111	(5,093)
Balance at the end of the period	(4,436)	(5,547)
Accumulated Other Comprehensive Loss
Changes in Accumulated Other Comprehensive Loss
Balance at the beginning of the period	(13,252)	(11,310)
Other comprehensive (loss) income before reclassifications of gain (loss)	5,239	(1,509)
Amount of gain (loss) reclassified from accumulated other comprehensive (loss) income	(81)	(433)
Total other comprehensive income	5,158	(1,942)
Balance at the end of the period	$ (8,094)	$ (13,252)

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Legal Proceedings (Details)			12 Months Ended
	Feb. 03, 2016 USD ($)	Oct. 05, 2015 a item	Dec. 31, 2015 USD ($)
Alleged Violations of Clean Air Act at Albany Terminal [Member]
Other legal proceedings
Terminal area (in acres) | a		63
Litigation Number of Plaintiffs Added | item		2
Alleged Violations of Clean Air Act at Albany Terminal [Member] | Subsequent event
Other legal proceedings
Damages sought	$ 37,500
Contract Dispute with Counterparty [Member]
Other legal proceedings
Estimated contract revenue, remainder of year			$ 13,200,000
Estimated contract revenue, after current year			$ 105,200,000
Contract term			4 years
Compliance with regulatory agencies | Transfer of Renewable Fuel Identification Numbers [Member]
Other legal proceedings
Damages sought			$ 12,000,000

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Quarterly Financial Data (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Unaudited quarterly financial data
Sales	$ 2,169,445	$ 2,486,203	$ 2,680,088	$ 2,979,116	$ 3,532,948	$ 4,050,458	$ 4,569,620	$ 5,116,928	$ 10,314,852	$ 17,269,954	$ 19,589,608
Gross profit	132,624	152,299	144,188	168,558	142,643	155,435	87,685	159,024	597,669	544,787	404,556
Net income	(2,905)	8,146	7,614	30,409	28,482	43,622	(12,278)	57,154	43,264	116,980	41,053
Net income attributable to Global Partners LP	(2,282)	8,212	7,218	30,415	27,910	42,508	(12,719)	57,010	43,563	114,709	42,615
Limited partners' interest in net (loss) income	$ (2,267)	$ 5,380	$ 4,547	$ 28,236	$ 26,093	$ 40,885	$ (13,752)	$ 55,502	$ 35,896	$ 108,728	$ 39,094
Basic net (loss) income per limited partner unit (in dollars per unit)	$ (0.70)	$ 0.16	$ 0.15	$ 0.92	$ 0.93	$ 1.50	$ (0.50)	$ 2.04	$ 1.12	$ 3.97	$ 1.43
Diluted net (loss) income per limited partner unit (in dollars per unit)	(0.70)	0.16	0.15	0.92	0.93	1.50	(0.50)	2.03	1.11	3.95	1.42
Cash distributions per limited partner unit (in dollars per unit)	$ 0.6975	$ 0.6925	$ 0.6800	$ 0.6650	$ 0.6525	$ 0.6375	$ 0.6250	$ 0.6125	$ 2.74	$ 2.53	$ 2.34
Loss due to customer dispute				$ 5,000
Restructuring charge to expense				2,300
Loss on disposition of assets					$ 1,100		$ 400	$ 700	$ (2,097)	$ (2,182)	$ 1,273
Warren Equities Inc
Unaudited quarterly financial data
Acquisition related costs incurred			$ 1,000	$ 4,400	$ 1,700
Capitol Petroleum Group
Unaudited quarterly financial data
Acquisition related costs incurred		$ 100	$ 3,100

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Subsequent Event (Details) $ in Millions		12 Months Ended
	Feb. 16, 2016 USD ($)	Dec. 31, 2015 location
GDSO
Subsequent Event
Number of non-strategic sites | location		100
Subsequent event | Common Units
Subsequent Event
Cash distribution to common unitholders | $	$ 15.8

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Supp Guarantor Cond Cons Fin Stmts - B/S (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	100.00%
Current assets:
Cash and cash equivalents	$ 1,116	$ 5,238	$ 9,217	$ 5,977
Accounts receivable, net	311,354	457,730
Accounts receivable-affiliates	2,578	3,903
Inventories	388,952	336,813
Brokerage margin deposits	31,327	17,198
Derivate assets	66,099	83,826
Prepaid expenses and other current assets	65,609	54,315
Total current assets	867,035	959,023
Property and equipment, net	1,242,683	825,051
Intangible assets, net	75,694	48,902
Goodwill	435,369	154,078
Other assets	42,894	43,763
Total assets	2,663,675	2,030,817
Current liabilities:
Accounts payable	303,781	456,619
Working capital revolving credit facility-current portion	98,100
Line of credit		700
Environmental liabilities-current portion	5,350	3,101
Trustee taxes payable	95,264	105,744
Accrued expenses and other current liabilities	60,328	82,820
Derivative liabilities	31,911	58,507
Total current liabilities	594,734	707,491
Working capital revolving credit facility-less current portion	150,000	100,000
Revolving credit facility	269,000	133,800
Senior notes	656,564	360,096
Environmental liabilities-less current portion	67,883	34,462
Financing obligation	89,790
Deferred tax liabilities	84,836	12,958
Other long-term liabilities	56,884	45,854
Total liabilities	1,969,691	1,394,661
Partners' equity
Total Global Partners LP equity	647,789	586,942
Noncontrolling interest	46,195	49,214
Total partners' equity	693,984	636,156	463,180	436,461
Total liabilities and partners' equity	2,663,675	2,030,817
Eliminations
Current assets:
Cash and cash equivalents	(3,574)
Accounts receivable-affiliates	(913)	(1,501)
Total current assets	(4,487)	(1,501)
Total assets	(4,487)	(1,501)
Current liabilities:
Cash overdraft	(3,574)
Accounts payable - affiliates	(913)	(1,501)
Total current liabilities	(4,487)	(1,501)
Total liabilities	(4,487)	(1,501)
Partners' equity
Total liabilities and partners' equity	(4,487)	(1,501)
(Issuer) Guarantor Subsidiaries
Current assets:
Cash and cash equivalents	(3,574)	2,560	8,371	$ 5,977
Accounts receivable, net	311,079	456,423
Accounts receivable-affiliates	2,745	4,584
Inventories	388,952	336,813
Brokerage margin deposits	31,327	17,198
Derivate assets	66,099	83,826
Prepaid expenses and other current assets	65,376	53,681
Total current assets	865,578	955,085
Property and equipment, net	1,203,251	778,385
Intangible assets, net	75,694	45,870
Goodwill	349,306	68,015
Other assets	42,894	43,763
Total assets	2,536,723	1,891,118
Current liabilities:
Cash overdraft	3,574
Accounts payable	303,242	455,629
Accounts payable - affiliates	746	820
Working capital revolving credit facility-current portion	98,100
Environmental liabilities-current portion	5,350	3,101
Trustee taxes payable	95,264	105,744
Accrued expenses and other current liabilities	59,742	81,686
Derivative liabilities	31,911	58,507
Total current liabilities	597,929	705,487
Working capital revolving credit facility-less current portion	150,000	100,000
Revolving credit facility	269,000	133,800
Senior notes	656,564	360,096
Environmental liabilities-less current portion	67,883	34,462
Financing obligation	89,790
Deferred tax liabilities	84,836	12,958
Other long-term liabilities	56,884	45,854
Total liabilities	1,972,886	1,392,657
Partners' equity
Total Global Partners LP equity	563,837	498,461
Total partners' equity	563,837	498,461
Total liabilities and partners' equity	2,536,723	1,891,118
Non-Guarantor Subsidiary
Current assets:
Cash and cash equivalents	4,690	2,678	$ 846
Accounts receivable, net	275	1,307
Accounts receivable-affiliates	746	820
Prepaid expenses and other current assets	233	634
Total current assets	5,944	5,439
Property and equipment, net	39,432	46,666
Intangible assets, net		3,032
Goodwill	86,063	86,063
Total assets	131,439	141,200
Current liabilities:
Accounts payable	539	990
Accounts payable - affiliates	167	681
Line of credit		700
Accrued expenses and other current liabilities	586	1,134
Total current liabilities	1,292	3,505
Total liabilities	1,292	3,505
Partners' equity
Total Global Partners LP equity	83,952	88,481
Noncontrolling interest	46,195	49,214
Total partners' equity	130,147	137,695
Total liabilities and partners' equity	$ 131,439	$ 141,200

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Supp Guarantor Cond Cons Fin Stmts - I/S (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Sales	$ 2,169,445	$ 2,486,203	$ 2,680,088	$ 2,979,116	$ 3,532,948	$ 4,050,458	$ 4,569,620	$ 5,116,928	$ 10,314,852	$ 17,269,954	$ 19,589,608
Cost of sales									9,717,183	16,725,167	19,185,052
Gross profit	132,624	152,299	144,188	168,558	142,643	155,435	87,685	159,024	597,669	544,787	404,556
Costs and operating expenses:
Selling, general and administrative expenses									177,043	153,961	115,491
Operating expenses									290,307	204,070	185,713
Amortization expense									13,499	18,867	19,216
Loss (gain) on sale and disposition of assets					(1,100)		(400)	(700)	2,097	2,182	(1,273)
Total costs and operating expenses									482,946	379,080	319,147
Operating income									114,723	165,707	85,409
Interest expense									(73,332)	(47,764)	(43,537)
Income before income tax expense									41,391	117,943	41,872
Income tax benefit (expense)									1,873	(963)	(819)
Net income	(2,905)	8,146	7,614	30,409	28,482	43,622	(12,278)	57,154	43,264	116,980	41,053
Net income attributable to noncontrolling interest									299	(2,271)	1,562
Net income attributable to Global Partners LP	(2,282)	8,212	7,218	30,415	27,910	42,508	(12,719)	57,010	43,563	114,709	42,615
Less: General partner's interest in net income, including incentive distribution rights									7,667	5,981	3,521
Limited partners' interest in net (loss) income	$ (2,267)	$ 5,380	$ 4,547	$ 28,236	$ 26,093	$ 40,885	$ (13,752)	$ 55,502	35,896	108,728	39,094
Eliminations
Sales									(15,190)	(25,976)	(14,382)
Cost of sales									(15,190)	(25,976)	(14,382)
(Issuer) Guarantor Subsidiaries
Sales									10,306,493	17,256,583	19,575,042
Cost of sales									9,722,340	16,743,163	19,194,385
Gross profit									584,153	513,420	380,657
Costs and operating expenses:
Selling, general and administrative expenses									174,925	150,964	110,228
Operating expenses									281,201	192,512	175,284
Amortization expense									10,467	7,846	7,106
Loss (gain) on sale and disposition of assets									2,097	2,182	(1,273)
Total costs and operating expenses									468,690	353,504	291,345
Operating income									115,463	159,916	89,312
Interest expense									(73,324)	(47,651)	(43,536)
Income before income tax expense									42,139	112,265	45,776
Income tax benefit (expense)									1,873	(963)	(819)
Net income									44,012	111,302	44,957
Net income attributable to Global Partners LP									44,012	111,302	44,957
Less: General partner's interest in net income, including incentive distribution rights									7,667	5,981	3,521
Limited partners' interest in net (loss) income									36,345	105,321	41,436
Non-Guarantor Subsidiary
Sales									23,549	39,347	28,948
Cost of sales									10,033	7,980	5,049
Gross profit									13,516	31,367	23,899
Costs and operating expenses:
Selling, general and administrative expenses									2,118	2,997	5,263
Operating expenses									9,106	11,558	10,429
Amortization expense									3,032	11,021	12,110
Total costs and operating expenses									14,256	25,576	27,802
Operating income									(740)	5,791	(3,903)
Interest expense									(8)	(113)	(1)
Income before income tax expense									(748)	5,678	(3,904)
Net income									(748)	5,678	(3,904)
Net income attributable to noncontrolling interest									299	(2,271)	1,562
Net income attributable to Global Partners LP									(449)	3,407	(2,342)
Limited partners' interest in net (loss) income									$ (449)	$ 3,407	$ (2,342)

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Supp Guarantor Cond Cons Fin Stmts - SCF (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Cash flows from operating activities
Net cash provided by operating activities	$ 62,506	$ 344,902	$ 255,147
Cash flows from investing activities
Acquisitions	(561,170)		(185,262)
Capital expenditures	(92,925)	(95,114)	(67,132)
Proceeds from sale of property and equipment	4,331	4,021	9,187
Net cash used in investing activities	(649,764)	(91,093)	(243,207)
Cash flows from financing activities
Proceeds from issuance of common units, net	109,305	137,844
Borrowings from (payments on) working capital revolving credit facility	148,100	(227,000)	(97,500)
Borrowings from revolving credit facility	135,200	(300,900)	12,700
Proceeds from issuance of term loan			115,000
Repayment of term loan			(115,000)
(Payments on) borrowings from line of credit	(700)	(3,000)	3,700
Proceeds from senior notes, net of discount	295,338	258,903	147,900
Repayment of senior notes		(40,244)
Repurchase of common units	(3,892)	(8,632)	(4,590)
Repurchased units withheld for tax obligations			(2,086)
Noncontrolling interest capital contribution	2,560	8,200	1,425
Distribution to noncontrolling interest	(5,280)	(9,200)	(2,920)
Distributions to partners	(97,495)	(73,759)	(67,329)
Net cash provided by (used in) financing activities	583,136	(257,788)	(8,700)
Cash and cash equivalents
(Decrease) increase in cash and cash equivalents	(4,122)	(3,979)	3,240
Cash and cash equivalents at beginning of period	5,238	9,217	5,977
Cash and cash equivalents at end of period	1,116	5,238	9,217
Eliminations
Cash and cash equivalents
Cash and cash equivalents at end of period	(3,574)
(Issuer) Guarantor Subsidiaries
Cash flows from operating activities
Net cash provided by operating activities	50,309	321,319	240,699
Cash flows from investing activities
Acquisitions	(561,170)		(94,179)
Capital expenditures	(90,240)	(78,863)	(53,484)
Proceeds from sale of property and equipment	4,331	4,021	9,179
Net cash used in investing activities	(647,079)	(74,842)	(138,484)
Cash flows from financing activities
Proceeds from issuance of common units, net	109,305	137,844
Borrowings from (payments on) working capital revolving credit facility	148,100	(227,000)	(97,500)
Borrowings from revolving credit facility	135,200	(300,900)	12,700
Proceeds from issuance of term loan			115,000
Repayment of term loan			(115,000)
Proceeds from senior notes, net of discount	295,338	258,903	147,900
Repayment of senior notes		(40,244)
Repurchase of common units	(3,892)	(8,632)	(4,590)
Repurchased units withheld for tax obligations			(2,086)
Noncontrolling interest capital contribution	9,360	10,700	(85,996)
Distribution to noncontrolling interest	(5,280)	(9,200)	(2,920)
Distributions to partners	(97,495)	(73,759)	(67,329)
Net cash provided by (used in) financing activities	590,636	(252,288)	(99,821)
Cash and cash equivalents
(Decrease) increase in cash and cash equivalents	(6,134)	(5,811)	2,394
Cash and cash equivalents at beginning of period	2,560	8,371	5,977
Cash and cash equivalents at end of period	(3,574)	2,560	8,371
Non-Guarantor Subsidiary
Cash flows from operating activities
Net cash provided by operating activities	12,197	23,583	14,448
Cash flows from investing activities
Acquisitions			(91,083)
Capital expenditures	(2,685)	(16,251)	(13,648)
Proceeds from sale of property and equipment			8
Net cash used in investing activities	(2,685)	(16,251)	(104,723)
Cash flows from financing activities
(Payments on) borrowings from line of credit	(700)	(3,000)	3,700
Noncontrolling interest capital contribution	(6,800)	(2,500)	87,421
Net cash provided by (used in) financing activities	(7,500)	(5,500)	91,121
Cash and cash equivalents
(Decrease) increase in cash and cash equivalents	2,012	1,832	846
Cash and cash equivalents at beginning of period	2,678	846
Cash and cash equivalents at end of period	$ 4,690	$ 2,678	$ 846

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SCHEDULE II-VALUATION AND QUALIFYING ACCOUNTS (Details) - Allowance for doubtful accounts-accounts receivable - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Changes in allowance for doubtful accounts during the period
Balance at Beginning of Period	$ 4,818	$ 7,513	$ 5,131
Charged to Costs and Expenses	1,303	1,700	4,145
Recoveries	42	277	9
Write Offs	(1,297)	(4,672)	(1,772)
Other Adjustment		1,076
Balance at End of Period	$ 5,942	$ 4,818	$ 7,513