Edgar Filing: GLOBAL PARTNERS LP

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-Q

(Mark One)

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

		For the quarterly period ended March 31, 2015

		OR

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

		For the transition period from to

Commission file number 001-32593

Global Partners LP

(Exact name of registrant as specified in its charter)

Delaware		74-3140887
(State or other jurisdiction of incorporation or organization)		(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)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes ý No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files.

Yes ý No o

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

Large accelerated filer o	Accelerated filer x	Non-accelerated filer o	Smaller reporting company o
		(Do not check if a smaller reporting company)

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

Yes o No ý

The issuer had 30,995,563 common units outstanding as of May 5, 2015.

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TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements (unaudited)	3

Consolidated Balance Sheets as of March 31, 2015 and December 31, 2014	3

Consolidated Statements of Income for the three months ended March 31, 2015 and 2014	4

Consolidated Statements of Comprehensive Income for the three months ended March 31, 2015 and 2014	5

Consolidated Statements of Cash Flows for the three months ended March 31, 2015 and 2014	6

Consolidated Statement of Partners’ Equity for the three months ended March 31, 2015	7

Notes to Consolidated Financial Statements	8

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	51

Item 3. Quantitative and Qualitative Disclosures about Market Risk	70

Item 4. Controls and Procedures	72

PART II. OTHER INFORMATION	73

Item 1. Legal Proceedings	73

Item 1A. Risk Factors	74

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	74

Item 6. Exhibits	75

SIGNATURES	77

INDEX TO EXHIBITS	78

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Item 1. Financial Statements

GLOBAL PARTNERS LP

CONSOLIDATED BALANCE SHEETS

(In thousands, except unit data)

(Unaudited)

	March 31,			December 31,
	2015			2014
Assets
Current assets:
Cash and cash equivalents	$	6,345		$	5,238
Accounts receivable, net	410,881			457,730
Accounts receivable—affiliates	3,845			3,903
Inventories	371,627			336,813
Brokerage margin deposits	33,737			17,198
Derivative assets	57,470			83,826
Prepaid expenses and other current assets	74,123			56,515
Total current assets	958,028			961,223
Property and equipment, net	1,174,083			825,051
Intangible assets, net	80,049			48,902
Goodwill	301,987			154,078
Other assets	54,637			50,723
Total assets	$	2,568,784		$	2,039,977
Liabilities and partners’ equity
Current liabilities:
Accounts payable	$	307,520		$	456,619
Working capital revolving credit facility—current portion	125,400			—
Line of credit	—			700
Environmental liabilities—current portion	3,085			3,101
Trustee taxes payable	90,183			105,744
Accrued expenses and other current liabilities	60,918			82,820
Derivative liabilities	48,272			58,507
Total current liabilities	635,378			707,491
Working capital revolving credit facility—less current portion	150,000			100,000
Revolving credit facility	517,400			133,800
Senior notes	368,316			368,136
Environmental liabilities—less current portion	72,186			34,462
Deferred tax liability	120,708			14,078
Other long-term liabilities	61,811			45,854
Total liabilities	1,925,799			1,403,821
Partners’ equity
Global Partners LP equity:
Common unitholders (30,995,563 units issued and 30,542,344 outstanding at March 31, 2015 and 30,995,563 units issued and 30,604,961 outstanding at December 31, 2014)	605,533			599,406
General partner interest (0.74% interest with 230,303 equivalent units outstanding at March 31, 2015 and December 31, 2014)	1,222			788
Accumulated other comprehensive loss	(12,978		)	(13,252		)
Total Global Partners LP equity	593,777			586,942
Noncontrolling interest	49,208			49,214
Total partners’ equity	642,985			636,156
Total liabilities and partners’ equity	$	2,568,784		$	2,039,977

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

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GLOBAL PARTNERS LP

CONSOLIDATED STATEMENTS OF INCOME

(In thousands, except per unit data)

(Unaudited)

		Three Months Ended March 31,
		2015			2014

Sales		$	2,979,116		$	5,116,928
Cost of sales		2,810,558			4,957,904
Gross profit		168,558			159,024

Costs and operating expenses:
Selling, general and administrative expenses		48,786			37,298
Operating expenses		68,656			47,952
Amortization expense		5,341			4,528
Loss on asset sales		437			663
Total costs and operating expenses		123,220			90,441

Operating income		45,338			68,583

Interest expense		(13,963		)	(11,107		)

Income before income tax expense		31,375			57,476

Income tax expense		(966		)	(322		)

Net income		30,409			57,154

Net loss (income) attributable to noncontrolling interest		6			(144		)

Net income attributable to Global Partners LP		30,415			57,010

Less:	General partner’s interest in net income, including incentive distribution rights	2,179			1,508

Limited partners’ interest in net income		$	28,236		$	55,502

Basic net income per limited partner unit		$	0.92		$	2.04

Diluted net income per limited partner unit		$	0.92		$	2.03

Basic weighted average limited partner units outstanding		30,599			27,261

Diluted weighted average limited partner units outstanding		30,712			27,296

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

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GLOBAL PARTNERS LP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In thousands)

(Unaudited)

	Three Months Ended March 31,
	2015		2014

Net income	$	30,409	$	57,154
Other comprehensive income:
Change in fair value of cash flow hedges	183		659
Change in pension liability	91		(609		)
Total other comprehensive income	274		50
Comprehensive income	30,683		57,204
Comprehensive loss (income) attributable to noncontrolling interest	6		(144		)
Comprehensive income attributable to Global Partners LP	$	30,689	$	57,060

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

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GLOBAL PARTNERS LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

	Three Months Ended March 31,
	2015			2014
Cash flows from operating activities
Net income	$	30,409		$	57,154
Adjustments to reconcile net income to net cash (used in) provided by in operating activities:
Depreciation and amortization	28,472			19,706
Amortization of deferred financing fees	1,459			1,283
Amortization of senior notes discount	179			105
Bad debt expense	35			250
Unit-based compensation expense	945			851
Loss on asset sales	437			663
Changes in operating assets and liabilities, excluding assets acquired:
Accounts receivable	52,186			41,898
Accounts receivable – affiliate	58			(234		)
Inventories	(15,614		)	112,328
Broker margin deposits	(16,539		)	6,599
Prepaid expenses, all other current assets and other assets	10,157			(11,416		)
Accounts payable	(170,646		)	(182,076		)
Trustee taxes payable	(21,099		)	701
Change in derivatives	16,121			17,252
Accrued expenses, all other current liabilities and other long-term liabilities	(30,475		)	(11,918		)
Net cash (used in) provided by operating activities	(113,915		)	53,146

Cash flows from investing activities
Acquisitions, net of cash acquired =	(405,478		)	—
Capital expenditures	(14,045		)	(13,075		)
Proceeds from sale of property and equipment	1,044			1,746
Net cash used in investing activities	(418,479		)	(11,329		)

Cash flows from financing activities
Borrowings from (payments on) working capital revolving credit facility	175,400			(20,200		)
Borrowings from revolving credit facility	383,600			—
Payments on line of credit	(700		)	—
Repurchase of common units	(2,442		)	—
Noncontrolling interest capital contribution	1,880			2,400
Distribution to noncontrolling interest	(1,880		)	(2,400		)
Distributions to partners	(22,357		)	(17,770		)
Net cash provided by (used in) financing activities	533,501			(37,970		)

Increase in cash and cash equivalents	1,107			3,847
Cash and cash equivalents at beginning of period	5,238			9,217
Cash and cash equivalents at end of period	$	6,345		$	13,064

Supplemental information
Cash paid during the period for interest	$	18,860		$	9,587

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

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GLOBAL PARTNERS LP

CONSOLIDATED STATEMENTS OF PARTNERS’ EQUITY

(In thousands)

(Unaudited)

							Accumulated
				General			Other						Total
	Common			Partner			Comprehensive			Noncontrolling			Partners’
	Unitholders			Interest			Loss			Interest			Equity

Balance at December 31, 2014	$	599,406		$	788		$	(13,252	)	$	49,214		$	636,156
Net income (loss)	28,236			2,179			—			(6		)	30,409
Noncontrolling interest capital contribution	—			—			—			1,880			1,880
Distribution to noncontrolling interest	—			—			—			(1,880		)	(1,880		)
Other comprehensive income	—			—			274			—			274
Unit-based compensation	945			—			—			—			945
Distributions to partners	(20,612		)	(1,745		)	—			—			(22,357		)
Repurchase of common units	(2,442		)	—			—			—			(2,442		)
Balance at March 31, 2015	$	605,533		$	1,222		$	(12,978	)	$	49,208		$	642,985

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

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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 and logistics of transporting petroleum and related products, including domestic and Canadian crude oil, gasoline and gasoline blendstocks (such as ethanol and naphtha), 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 March 31, 2015, the Partnership had a portfolio of 1,447 owned, leased and/or supplied gasoline stations, including 287 convenience stores, primarily 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, through the Partnership’s wholly owned subsidiary, Global Companies LLC (“Global Companies”), the Partnership acquired the Revere terminal (the “Revere Terminal”) located in Boston Harbor in Revere, Massachusetts from Global Petroleum Corp. (“GPC”). See Note 2.

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 or Drake Petroleum Company, Inc. (“Drake Petroleum”).

The General Partner, which holds a 0.74% general partner interest in the Partnership, is owned by affiliates of the Slifka family. As of March 31, 2015, affiliates of the General Partner, including its directors and executive officers and their affiliates, owned 7,293,722 common units, representing a 23.5% limited partner interest.

Ownership by affiliates of the General Partner decreased by approximately 4,446,575 common units (from 37.9% to 23.5%) primarily as a result of the liquidation and dissolution of AE Holdings Corp. (“AE Holdings”). Immediately prior to such liquidation and dissolution, the directors and executive officers of the General Partner were deemed to beneficially own the entire 5,850,000 common units that were then owned by AE Holdings. Upon the liquidation and dissolution 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 the stockholders of AE Holdings to cover their respective tax liabilities resulting from their receipt of the common units. Approximately 2,306,960 common units of the original 5,850,000 common units are held by the directors and executive officers of the General Partner, and the remaining 1,586,806 common units are held by unaffiliated members of the Slifka family.

Basis of Presentation

The financial results of Warren and the Revere Terminal for the three months ended March 31, 2015 are included in the accompanying statements of income for the three months ended March 31, 2015. The accompanying consolidated financial statements as of March 31, 2015 and December 31, 2014 and for the three months ended March 31, 2015 and 2014 reflect the accounts of the Partnership. Upon consolidation, all intercompany balances and transactions have been eliminated.

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1. Organization and Basis of Presentation (continued)

The accompanying unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) and reflect all adjustments (consisting of normal recurring adjustments) which are, in the opinion of management, necessary for a fair presentation of the financial condition and operating results for the interim periods. The interim financial information, which has been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”), should be read in conjunction with the consolidated financial statements for the year ended December 31, 2014 and notes thereto contained in the Partnership’s Annual Report on Form 10-K. The significant accounting policies described in Note 2, “Summary of Significant Accounting Policies,” of such Annual Report on Form 10-K are the same used in preparing the accompanying consolidated financial statements.

The results of operations for the three months ended March 31, 2015 are not necessarily indicative of the results of operations that will be realized for the entire year ending December 31, 2015. The consolidated balance sheet at December 31, 2014 has been derived from the audited consolidated financial statements included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2014.

Due to the nature of the Partnership’s business and its reliance, in part, on consumer travel and spending patterns, the Partnership may experience more demand for gasoline and gasoline blendstocks during the late spring and summer months than during the fall and winter. Travel and recreational activities are typically higher in these months in the geographic areas in which the Partnership operates, increasing the demand for gasoline and gasoline blendstocks that the Partnership distributes. Therefore, the Partnership’s volumes in gasoline and gasoline blendstocks are typically higher in the second and third quarters of the calendar year. As demand for some of the Partnership’s refined petroleum products, specifically home heating oil and residual oil for space heating purposes, is generally greater during the winter months, heating oil and residual oil sales are generally higher during the first and fourth quarters of the calendar year. These factors may result in fluctuations in the Partnership’s quarterly operating results.

Reclassification

Certain prior year amounts in the consolidated financial statements have been reclassified to conform to the current year presentation.

Noncontrolling Interest

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

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

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1. Organization and Basis of Presentation (continued)

Concentration of Risk

The following table presents the Partnership’s sales, logistics revenue and rental income as a percentage of the consolidated sales for the periods presented:

	Three Months Ended March 31,
	2015	2014
Gasoline sales: gasoline and gasoline blendstocks such as ethanol and naphtha	50%	54%
Crude oil sales and logistics revenue	9%	12%
Distillates (home heating oil, diesel and kerosene), residual oil, natural gas and propane sales	38%	33%
Convenience store sales, rental income and sundry sales	3%	1%
Total	100%	100%

None of the Partnership’s customers were significant for the three months ended March 31, 2015. The Partnership had one significant customer, ExxonMobil Corporation (“ExxonMobil”) that accounted for approximately 14% of total sales for the three months ended March 31, 2014.

Note 2. Business Combinations

Acquisition of Warren Equities, Inc.

On January 7, 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 320 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 Financial Accounting Standards Board’s (“FASB”) guidance regarding business combinations. The Partnership’s financial statements include the results of operations of Warren subsequent to the acquisition date.

The purchase price allocation is considered preliminary, and additional adjustments may be recorded during the allocation period in accordance with the FASB’s guidance regarding business combinations. The purchase price allocation will be finalized as the Partnership receives additional information relevant to the acquisition, including a final valuation of the assets purchased, including tangible and intangible assets, and liabilities assumed.

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 2. Business Combinations (continued)

The following table presents the preliminary 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	$	5,372
Inventory	19,199
Prepaid expenses	12,552
Property and equipment	331,291
Intangibles	36,490
Other non-current assets	20,586
Total identifiable assets purchased	425,490
Liabilities assumed:
Accounts payable	(21,511		)
Assumption of environmental liabilities	(36,080		)
Taxes payable	(5,538		)
Accrued expenses	(11,595		)
Long-term deferred taxes	(105,855		)
Other non-current liabilities	(10,992		)
Total liabilities assumed	(191,571		)
Net identifiable assets acquired	233,919
Goodwill	147,909
Net assets acquired	$	381,828

Management is currently in the process of evaluating the purchase price accounting. The Partnership has engaged a third-party valuation firm to assist in the valuation of Warren’s property and equipment, intangibles and leasehold interests. This valuation continues to be in progress and, during the quarter ended March 31, 2015, the Partnership received preliminary fair values of these assets. The estimated fair values of property and equipment of $331.3 million and intangibles assets, primarily supply contracts, of $36.5 million were developed by management based on their estimates, assumptions and acquisition history including preliminary reports from a third-party valuation firm. The estimated fair values of the property and equipment, intangibles and leasehold interests will be supported by valuations performed by a third party.

The fair value of $36.1 million assigned to the assumption of environmental liabilities was estimated by management based on their estimates, assumptions and acquisition history, including preliminary reports from third-party environmental engineers (see Note 11). The fair value of this liability will be supported by a third-party environmental specialist.

The long-term deferred taxes of $105.9 million are 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 fair values of the remaining Warren assets and liabilities noted above approximate their carrying values at January 7, 2015. It is possible that once the Partnership receives the completed valuations on the property and equipment and intangible assets, the final purchase price accounting may be different than what is presented above.

The preliminary 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 on their estimates and assumptions. Any excess purchase price over the fair value of the net tangible and intangible assets acquired was allocated to goodwill.

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 2. Business Combinations (continued)

The Partnership utilized accounting guidance related to intangible assets which lists the pertinent factors to be considered when estimating the useful life of an intangible asset. These factors include, in part, a review of the expected use by the Partnership of the assets acquired, the expected useful life of another asset (or group of assets) related to the acquired assets and legal, regulatory or other contractual provisions that may limit the useful life of an acquired asset. The Partnership amortizes these intangible assets over their estimated useful lives which is consistent with the estimated undiscounted future cash flows of these assets.

As part of the purchase price allocation, identifiable intangible assets include supply contracts that are being amortized over ten years. 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 supply contracts had a weighted average term of approximately 5 years prior to their next renewal. As the purchase price accounting is preliminary, the final assumptions related to the likelihood of renewals remains in process. For the three months ended March 31, 2015, amortization expense amounted to $0.8 million. The estimated remaining amortization expense for intangible assets acquired in connection with the acquisition for each of the five succeeding years and thereafter is as follows (in thousands):

2015 (1/7/15 – 12/31/15)	$	2,685
2016	3,580
2017	3,580
2018	3,580
2019	3,580
Thereafter	17,960
Total	$	34,965

The $147.9 million of goodwill was 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. The goodwill is not deductible for income tax purposes. The Partnership is responsible for federal 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.

In connection with the acquisition of Warren, the Partnership incurred acquisition costs totaling approximately $6.1 million, of which $4.4 million was recorded for the three months ended March 31, 2015 and included in selling, general and administrative expenses in the accompanying consolidated statement of income. The remaining acquisition costs were incurred in 2014. Additionally, 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 income for the three months ended March 31, 2015. This charge, which is principally for redundant and/or eliminated positions as a result of the acquisition, was not part of the purchase price allocation. Approximately $0.5 million of the restructuring charge was paid during the three months ended March 31, 2015, and the remaining balance of $1.8 million is expected to be paid in full by 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 acquisition added approximately 500 million gallons of fuel sold annually through the Partnership’s network and increased the number of its total gasoline stations that it owns, leases or supplies to more than 1,500 as of the acquisition closing date. The Warren operations have been integrated into the Partnership’s GDSO reporting segment.

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 2. Business Combinations (continued)

Acquisition of 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, for a purchase price of $23.65 million. The acquisition includes contingent consideration which would be payable under specific circumstances involving a subsequent sale of the property, and the purchase price may be adjusted in connection with any value assigned to the contingent consideration as the purchase price accounting is finalized. The Partnership financed the transaction with available capacity 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 has 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.

At March 31, 2015, the Partnership’s preliminary purchase accounting includes estimated fair values of $28.3 million associated with the property and equipment acquired and $4.6 million of assumed liabilities. The purchase price allocation will be finalized as the Partnership receives additional information relevant to the acquisition.

Goodwill

The following table presents the changes in 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	—		147,909		147,909
Balance at March 31, 2015	$	121,752	$	180,235	$	301,987

Supplemental Pro Forma Information

Revenues and net income 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 three months ended March 31, 2015 is consistent with the amounts reported in the accompanying statement of income for the three months ended March 31, 2015.

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 the period presented, with pro forma adjustments to give effect to intercompany sales and certain other adjustments (in thousands, except per unit data):

	Three Months
	Ended
	March 31, 2014
Sales	$	5,496,851
Net income attributable to Global Partners LP	$	51,637
Net income per limited partner unit, basic and diluted	$	1.84

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 2. Business Combinations (continued)

Warren’s revenues and net loss included in the Partnership’s consolidated operating results from January 7, 2015, the acquisition date, through the period ended March 31, 2015 were $247.7 million and $(1.0 million), respectively.

Note 3. 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 March 31, 2015 and December 31, 2014 excluded 453,219 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).

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 for the three months ended March 31, 2015 and 2014 (in thousands, except per unit data):

	Three Months March 31, 2015									Three Months Ended March 31, 2014
Numerator:	Total		Limited Partner Interest		General Partner Interest			IDRs		Total		Limited Partner Interest		General Partner Interest		IDRs
Net income attributable to Global Partners LP (1)	$	30,415	$	28,236	$	2,179		$	—	$	57,010	$	55,502	$	1,508	$	—

Declared distribution	$	23,260	$	21,076	$	157		$	2,027	$	18,323	$	17,145	$	143	$	1,035
Assumed allocation of undistributed net income	7,155		7,160		(5		)	—		38,687		38,357		330		—
Assumed allocation of net income	$	30,415	$	28,236	$	152		$	2,027	$	57,010	$	55,502	$	473	$	1,035

Denominator:
Basic weighted average limited partner units outstanding			30,599									27,261
Dilutive effect of phantom units			113									35
Diluted weighted average limited partner units outstanding			30,712									27,296

Basic net income per limited partner unit			$	0.92								$	2.04
Diluted net income per limited partner unit			$	0.92								$	2.03

(1) As a result of the December 10, 2014 issuance of 3,565,000 common units in connection with the Partnership’s public offering, the general partner interest was reduced to 0.74% for the three months ended March 31, 2015 from 0.83% for the three months ended March 31, 2014.

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(Unaudited)

Note 3. Net Income Per Limited Partner Unit (continued)

During 2015, the board of directors of the General Partner declared the following quarterly cash distribution:

Cash Distribution	Per Unit Cash	Distribution Declared for the
Declaration Date	Distribution Declared	Quarterly Period Ended
April 22, 2015	$0.68 (1)	March 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 8, “Cash Distributions” for further information.

Note 4. 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, on a first-in, first-out basis, or market.

Inventories consisted of the following (in thousands):

	March 31,		December 31,
	2015		2014
Distillates: home heating oil, diesel and kerosene	$	103,057	$	163,679
Gasoline	96,846		82,080
Gasoline blendstocks	47,651		33,760
Crude oil	86,385		20,769
Residual oil	13,172		20,602
Propane and other	2,037		5,123
Renewable identification numbers (RINs)	1,213		2,057
Convenience store inventory	21,266		8,743
Total	$	371,627	$	336,813

In addition to its own inventory, the Partnership has exchange agreements for petroleum products with unrelated third-party suppliers, whereby it may draw inventory from these other suppliers and suppliers may draw inventory from the Partnership. Positive exchange balances are accounted for as accounts receivable and amounted to $9.6 million and $3.9 million at March 31, 2015 and December 31, 2014, respectively. Negative exchange balances are accounted for as accounts payable and amounted to $12.1 million and $16.5 million at March 31, 2015 and December 31, 2014, respectively. Exchange transactions are valued using current carrying costs and have no income statement impact.

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(Unaudited)

Note 5. 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.

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

		Units (1)		Unit of Measure

Exchange-Traded Derivatives
Long		46,736		Thousands of barrels
Short		(50,292	)	Thousands of barrels

OTC Derivatives (Petroleum/Ethanol)
Long		13,318		Thousands of barrels
Short		(10,167	)	Thousands of barrels

OTC Derivatives (Natural Gas)
Long		10,607		Thousands of decatherms
Short		(10,661	)	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)	$	6.0		Millions of Canadian dollars
	$	4.7		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 (“CAD”) $1.2662 to USD $1.00.

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(Unaudited)

Note 5. Derivative Financial Instruments (continued)

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 income through cost of sales. These futures contracts are settled on a daily basis by the Partnership through brokerage margin accounts.

The Partnership’s fair value hedges include exchange-traded futures 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 income.

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 income for the three months ended March 31, 2015 and 2014 (in thousands):

	Statement of Gain (Loss)	Three Months Ended
	Recognized in Income on	March 31,
	Derivatives	2015			2014
Derivatives in fair value hedging relationship
Exchange-traded futures contracts for petroleum commodity products	Cost of sales	$	26,176		$	16,373

Hedged items in fair value hedge relationship
Physical inventory	Cost of sales	$	(23,621	)	$	(16,209	)

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 hedges, 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 income through interest expense in the same period that the hedged exposure affects earnings. The ineffective portion is recognized in the consolidated statement of income immediately.

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(Unaudited)

Note 5. Derivative Financial Instruments (continued)

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 6), 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 March 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 income 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 income and partners’ equity for the three months ended March 31, 2015 and 2014 (in thousands):

	Amount of Gain (Loss)					Location of Gain (Loss)
	Recognized in Other					Reclassified from	Amount of Gain (Loss)
	Comprehensive Income on					Accumulated Other	Reclassified from Other
	Derivatives					Comprehensive Income into	Comprehensive Income into
	(Effective Portion)					Income (Effective Portion)	Income (Effective Portion)
Derivatives Designated	Three Months Ended						Three Months Ended
in Cash Flow Hedging	March 31,						March 31,
Relationship	2015		2014				2015		2014
Interest rate swaps	$	47	$	677		Interest expense	$	—	$	—
Interest rate cap (1)	—		(18		)	Interest expense	—		—
Total	$	47	$	659			$	—	$	—

(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 three months ended March 31, 2015. As of March 31, 2015, the remaining unamortized prepaid interest rate caplets were $0.9 million and will be amortized over the remaining life for the interest rate cap which expires in April 2016.

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(Unaudited)

Note 5. Derivative Financial Instruments (continued)

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

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 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 income through cost of sales. These futures contracts are settled on a daily basis by the Partnership through brokerage margin accounts.

While the Partnership seeks to maintain a position that is substantially balanced within its 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 income 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 fixed price purchase and sale commitments are recognized in the consolidated statement of income 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.

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(Unaudited)

Note 5. Derivative Financial Instruments (continued)

The following table presents the gains and losses from the Partnership’s derivative instruments not involved in hedging relationships recognized in the consolidated statements of income for the three months ended March 31, 2015 and 2014 (in thousands):

	Statement of Gain (Loss)	Three Months Ended
	Recognized in Income on	March 31,
	Derivatives	2015		2014
Derivatives NOT designated as hedging instruments
Commodity contracts	Cost of sales	$	3,651	$	15,543
Forward foreign currency contracts	Cost of sales	18		(57		)
Total		$	3,669	$	15,486

Margin Deposits

All of 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.

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 quality 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 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.

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(Unaudited)

Note 5. Derivative Financial Instruments (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 March 31, 2015 and December 31, 2014 (in thousands):

		March 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	$	17,895	$	60,354	$	78,249
Forward derivative contracts (1)	Derivative assets	—		57,470		57,470
Forward foreign currency contracts	Other Assets	—		27		27
Interest rate cap contract	Other assets	—		17		17
Total asset derivatives		$	17,895	$	117,868	$	135,763

Liability Derivatives
Forward derivative contracts (1)	Derivative liabilities	$	—	$	48,272	$	48,272
Interest rate swap contracts	Other long-term liabilities	—		6,649		6,649
Total liability derivatives		$	—	$	54,921	$	54,921

		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.

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(Unaudited)

Note 5. Derivative Financial Instruments (continued)

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.

Note 6. Debt

Credit Agreement

As of March 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”). The Credit Agreement will mature on April 30, 2018.

As of March 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, for a total credit facility of up to $2.075 billion. The Partnership cannot provide assurance, however, that its lending group will agree to fund any request by the Partnership for additional amounts in excess of the total available commitments of $1.775 billion.

In addition, the Credit Agreement includes a swing line pursuant to which Bank of America, N.A., as the swing line lender, may make swing line loans in U.S. Dollars in an aggregate amount equal to the lesser of (a) $50.0 million and (b) the Aggregate WC Commitments (as defined in the Credit Agreement). Swing line loans will bear interest at the Base Rate (as defined in the Credit Agreement). The swing line is a sub-portion of the working capital revolving credit facility and is not an addition to the total available commitments of $1.775 billion.

Pursuant to the Credit Agreement, and in connection with any agreement by and between a Loan Party and a Lender (as such terms are defined in the Credit Agreement) or affiliate thereof (an “AR Buyer”), a Loan Party may sell certain of its accounts receivables to an AR Buyer. The 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.

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(Unaudited)

Note 6. Debt (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 interest rates for the Credit Agreement were 3.4% and 3.6% for the three months ended March 31, 2015 and 2014, respectively.

As of March 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 5 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 long-term liability representing the amounts expected to be outstanding during the entire year, and because the Partnership has a multi-year, long-term commitment from its bank group. The long-term portion of the working capital revolving credit facility was $150.0 million and $100.0 million at March 31, 2015 and December 31, 2014, respectively. In addition, the Partnership classifies a portion of its working capital revolving credit facility as a current liability because it repays amounts outstanding and reborrows funds based on its working capital requirements. The Partnership’s current portion of the working capital revolving credit facility represents the amount the Partnership expects to pay down during the course of the year. At March 31, 2015 and December 31, 2014, the current portion of the working capital revolving credit facility was $125.4 million and $0, respectively. The increase in total borrowings under the working capital revolving credit facility from December 31, 2014 reflects, in part, higher levels of stored inventory, and the Partnership expects to pay down a portion of its borrowings during the course of the year and has classified the amount as current at March 31, 2015.

As of March 31, 2015, the Partnership had total borrowings outstanding under the Credit Agreement of $792.8 million, including $517.4 million outstanding on the revolving credit facility. In addition, the Partnership had outstanding letters of credit of $59.8 million. Subject to borrowing base limitations, the total remaining availability for borrowings and letters of credit was $0.9 billion and $1.4 billion at March 31, 2015 and December 31, 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.

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(Unaudited)

Note 6. Debt (continued)

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 March 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).

6.25% Senior Notes

On June 19, 2014, the Partnership and GLP Finance (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.

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Note 6. Debt (continued)

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 have been 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 matures on December 9, 2015 and had an outstanding balance of $0 and $0.7 million at March 31, 2015 and December 31, 2014, respectively. The facility is secured by substantially all of the assets of Basin Transload and is not guaranteed by the Partnership or any of its wholly owned subsidiaries.

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 did not capitalize additional financing fees for the three months ended March 31, 2015 and 2014. Amortization expense of approximately $1.5 million and $1.3 million for the three months ended March 31, 2015 and 2014, respectively, are included in interest expense in the accompanying consolidated statements of income. Unamortized fees are included in other current assets and other long-term assets.

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Note 7. 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 the Terminal Storage Rental and Throughput Agreement has terminated (see Note 2). Prior to the acquisition, the agreement was accounted for as an operating lease. The expenses under this agreement totaled $0.8 million and $2.3 million for the three months ended March 31, 2015 and 2014, 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 and $24,000 for the three months ended March 31, 2015 and 2014, respectively. These charges were recorded in selling, general and administrative expenses in the accompanying consolidated statements of income.

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,” and together with the AE Holdings Amended and Restated Services Agreement,” the “Amended and Restated Services Agreements”).

Under the AE Holdings Amended and Restated Services Agreement, the Partnership continues to provide AE Holdings with certain tax, accounting, treasury and legal support services for which AE Holdings pays the Partnership an aggregate of $15,000 per year in equal monthly installments. 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 Amended and Restated Services Agreements are each for an indefinite term and any party may terminate some or all of the services upon ninety (90) days’ advanced written notice. As of March 31, 2015, no such notice of termination was given by any party.

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 or Drake Petroleum. The Partnership reimburses the General Partner for expenses incurred in connection with these employees. These expenses, including payroll, payroll taxes and bonus accruals, were $29.4 million and $19.0 million for the three months ended March 31, 2015 and 2014, respectively. The Partnership also reimburses the General Partner for its contributions under the General Partner’s 401(k) Savings and Profit Sharing Plan 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 (in thousands):

	March 31,		December 31,
	2015		2014
Receivables from GPC	$	—	$	108
Receivables from the General Partner (1)	3,845		3,795
Total	$	3,845	$	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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Note 8. Cash Distributions

The Partnership intends to consider regular cash distributions to unitholders on a quarterly basis, although there is no assurance as to the future cash distributions since they are dependent upon future earnings, capital requirements, financial condition and other factors. The Credit Agreement prohibits the Partnership from making cash distributions if any potential default or Event of Default, as defined in the Credit Agreement, occurs or would result from the cash distribution.

Within 45 days after the end of each quarter, the Partnership will distribute all of its Available Cash (as defined in its partnership agreement) to unitholders of record on the applicable record date. The amount of Available Cash is all cash on hand on the date of determination of Available Cash for the quarter; less the amount of cash reserves established by the General Partner to provide for the proper conduct of the Partnership’s business, to comply with applicable law, any of the Partnership’s debt instruments, or other agreements or to provide funds for distributions to unitholders and the General Partner for any one or more of the next four quarters.

The Partnership will make distributions of Available Cash from distributable cash flow for any quarter in the following manner: 99.26% to the common unitholders, pro rata, and 0.74% 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:

	Total Quarterly Distribution	Marginal Percentage Interest in Distributions
	Target Amount	Unitholders	General Partner
First Target Distribution	up to $0.4625	99.26%	0.74%
Second Target Distribution	above $0.4625 up to $0.5375	86.26%	13.74%
Third Target Distribution	above $0.5375 up to $0.6625	76.26%	23.74%
Thereafter	above $0.6625	51.26%	48.74%

The Partnership paid the following cash distribution during 2015 (in thousands, except per unit data):

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

02/13/15 (1)	$	0.6650	$	20,612	$	154	$	1,591	$	22,357

(1) This distribution of $0.6650 per unit resulted in the Partnership exceeding its third target level distribution for the fourth quarter of 2014. As a result, the General Partner, as the holder of the IDRs, received an incentive distribution.

In addition, on April 22, 2015, the board of directors of the General Partner declared a quarterly cash distribution of $0.68 per unit ($2.72 per unit on an annualized basis) on all of its outstanding common units for the period from January 1, 2015 through March 31, 2015 to the Partnership’s unitholders of record as of the close of business on May 6, 2015. This distribution will result in the Partnership exceeding its third target level distribution for the quarter ended March 31, 2015.

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Note 9. Segment Reporting

The Partnership engages in the purchasing, selling and logistics of transporting petroleum and related products, including domestic and Canadian crude oil, gasoline and gasoline blendstocks (such as ethanol and naphtha), 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 three months ended March 31, 2015 and 2014, 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 Partnership’s Annual Report on Form 10-K for the year ended December 31, 2014.

In the Wholesale reporting segment, the Partnership sells branded and unbranded gasoline and gasoline blendstocks and diesel to branded and unbranded gasoline customers and other resellers of transportation fuels. 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 distillate products 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 convenience stores, rental income from gasoline stations leased to dealers or commissioned agents and sundry (car wash sales, lottery and ATM commissions). The results of Warren, acquired in January 2015 (see Note 2), 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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Note 9. Segment Reporting (continued)

Summarized financial information for the Partnership’s reportable segments is presented in the table below (in thousands):

	Three Months Ended
	March 31,
	2015			2014
Wholesale Segment:
Sales
Gasoline and gasoline blendstocks	$	776,143		$	1,994,556
Crude oil (1)	252,110			591,229
Other oils and related products (2)	943,693			1,412,771
Total	$	1,971,946		$	3,998,556
Product margin
Gasoline and gasoline blendstocks	$	29,829		$	49,663
Crude oil (1)	15,257			23,490
Other oils and related products (2)	35,007			34,616
Total	$	80,093		$	107,769
Gasoline Distribution and Station Operations Segment (3):
Sales
Gasoline	$	697,334		$	768,904
Station operations (4)	83,075			33,972
Total	$	780,409		$	802,876
Product margin
Gasoline	$	61,699		$	33,280
Station operations (4)(5)	36,723			19,797
Total	$	98,422		$	53,077
Commercial Segment:
Sales	$	226,761		$	315,496
Product margin	$	11,558		$	12,329
Combined sales and product margin:
Sales	$	2,979,116		$	5,116,928
Product margin (6)	$	190,073		$	173,175
Depreciation allocated to cost of sales	(21,515		)	(14,151		)
Combined gross profit	$	168,558		$	159,024

(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) For the three months ended March 31, 2015, the GDSO segment includes the January 2015 acquisition of Warren (see Note 2). As the Warren assets were not in place prior to January 2015, the above results are not directly comparable to the prior period.

(4) Station operations primarily consist of convenience stores sales at the Partnership’s directly operated stores and rental income from gasoline stations leased to dealers or commissioned agents.

(5) For the three months ended March 31, 2014, station operations includes the reclass of loss on asset sales 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 our consolidated financial statements to assess our business. The table above includes a reconciliation of product margin on a combined basis to gross profit, a directly comparable GAAP measure.

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Note 9. Segment Reporting (continued)

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

	Three Months Ended
	March 31,
	2015			2014
Combined gross profit	$	168,558		$	159,024
Operating costs and expenses not allocated to operating segments:
Selling, general and administrative expenses	48,786			37,298
Operating expenses	68,656			47,952
Amortization expense	5,341			4,528
Loss on asset sales	437			663
Total operating costs and expenses	123,220			90,441
Operating income	45,338			68,583
Interest expense	(13,963		)	(11,107		)
Income tax expense	(966		)	(322		)
Net income	30,409			57,154
Net (income) loss attributable to noncontrolling interest	6			(144		)
Net income attributable to Global Partners LP	$	30,415		$	57,010

The Partnership’s foreign assets and foreign sales were immaterial as of and for the three months ended March 31, 2015 and 2014.

Segment Assets

The Partnership acquired retail gasoline stations from Warren in January 2015, Alliance in March 2012 and ExxonMobil in September 2010 which have been allocated to the GDSO segment. The Partnership acquired the Revere Terminal in January 2015 and transloading facilities and other assets from Basin Transload and Cascade Kelly Holdings LLC (“Cascade Kelly”) in February 2013 which have been 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 March 31, 2015 and December 31, 2014 (in thousands):

	Wholesale		Commercial		GDSO		Unallocated		Total
March 31, 2015	$	773,803	$	—	$	1,184,978	$	610,003	$	2,568,784
December 31, 2014	$	811,535	$	—	$	622,860	$	605,582	$	2,039,977

The increase in total GDSO and total consolidated assets at March 31, 2015 compared to December 31, 2014 is due to the January 2015 acquisitions of Warren and the Revere Terminal (Note 2).

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Note 10. Property and Equipment

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

	March 31,			December 31,
	2015			2014
Buildings and improvements	$	930,169		$	667,172
Land	384,078			288,929
Fixtures and equipment	32,985			26,577
Construction in process	72,213			66,119
Capitalized internal use software	7,530			7,530
Total property and equipment	1,426,975			1,056,327
Less accumulated depreciation	(252,892		)	(231,276		)
Total	$	1,174,083		$	825,051

At March 31, 2015 and December 31, 2014, construction in process included $30.5 million related to the Partnership’s ethanol plant acquired from Cascade Kelly. Due to the nature of certain assets acquired from Cascade Kelly which are currently idle, the Partnership intends to make the capital improvements necessary to place the ethanol plant into service and expects the plant to be operational in 2016; therefore, as of March 31, 2015 and December 31, 2014, the recorded value of the ethanol plant is included in construction in process. After the plant has been successfully placed into service, depreciation will commence.

As part of continuing operations, the Partnership may periodically divest certain gasoline stations. The gain (loss) on the sale, representing cash proceeds less net book value of assets at disposition, is recorded in loss on asset sales in the accompanying consolidated statements of income and amounted to $0.4 million and $0.7 million for the three months ended March 31, 2015 and 2014, respectively.

The Partnership evaluates its assets for impairment on a quarterly basis. No impairments were required for the three months ended March 31, 2015 and 2014.

Note 11. Environmental Liabilities, Asset Retirement Obligations and Renewable Identification Numbers (RINs)

Environmental Liabilities

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

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

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Note 11. Environmental Liabilities, Asset Retirement Obligations and Renewable Identification Numbers (RINs) (continued)

In connection with the January 2015 acquisition of the Revere Terminal (see Note 2), the Partnership assumed certain environmental liabilities, including certain ongoing environmental remediation efforts. As a result, the Partnership recorded, on an undiscounted basis, a total environmental liability of approximately $2.9 million.

In connection with the January 2015 acquisition of Warren (see Note 2), 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 recorded, on an undiscounted basis, a total environmental liability of approximately $36.1 million.

Both the $2.9 million and $36.1 million recorded for the Revere Terminal and for Warren, respectively, were based on preliminary purchase accounting. These amounts may change as the purchase price accounting is finalized.

In connection with the December 2012 acquisition of six New England retail gasoline stations from Mutual Oil, 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 $0.6 million.

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 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.

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.

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Note 11. Environmental Liabilities, Asset Retirement Obligations and Renewable Identification Numbers (RINs) (continued)

In connection with the November 2007 acquisition of ExxonMobil’s Glenwood Landing and Inwood, New York terminals, the Partnership assumed certain environmental liabilities, including the remediation obligations under remedial action plans submitted by ExxonMobil to and approved by the New York Department of Environmental Conservation (“NYDEC”) with respect to both terminals. As a result, the Partnership initially recorded, on an undiscounted basis, total environmental liabilities of approximately $1.2 million.

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

	Balance at													Balance at
	December 31,		Additions in		Payments in			Dispositions			Other			March 31,
Environmental Liability Related to:	2014		2015		2015			2015			Adjustments			2015
Retail Gasoline Stations	$	35,792	$	36,080	$	(1,017	)	$	(67	)	$	(172	)	$	70,616
Terminals	1,771		2,900		(16		)	—			—			4,655
Total environmental liabilities	$	37,563	$	38,980	$	(1,033	)	$	(67	)	$	(172	)	$	75,271

Current portion	$	3,101												$	3,085
Long-term portion	34,462													72,186
Total environmental liabilities	$	37,563												$	75,271

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.

Asset Retirement Obligations

The Partnership is required to account for the legal obligations associated with the long-lived assets that result from the acquisition, construction, development or operation of long-lived assets. Such asset retirement obligations specifically pertain to the treatment of underground gasoline storage tanks (“USTs”) that exist in those U.S. states which statutorily require removal of the USTs at a certain point in time. Specifically, the Partnership’s retirement obligations consist of the estimated costs of removal and disposals of USTs in specific states.

The fair value of a liability for an asset retirement obligation is recognized in the year in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying cost of the asset. The Partnership had approximately $5.7 million and $3.8 million in total asset retirement obligations at March 31, 2015 and December 31, 2014, respectively, which are included in other long-term liabilities in the accompanying balance sheets. Approximately $1.8 million of this obligation at March 31, 2015 was assumed in the acquisition of Warren and is based on preliminary purchase accounting. This amount may change as the purchase price accounting is finalized.

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Note 11. Environmental Liabilities, Asset Retirement Obligations and Renewable Identification Numbers (RINs) (continued)

Renewable Identification Numbers (RINs)

A Renewable Identification Number (“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 Environmental Protection Agency’s (the “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 $0.3 million and $0.3 million at March 31, 2015 and December 31, 2014, respectively.

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

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 initially 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, 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 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.

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Note 12. Long-Term Incentive Plan (continued)

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, and during the three months ended March 31, 2015, a total of 17,870 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.

The Partnership recorded total compensation expense related to these of $1.0 million and $0.9 million for the three months ended March 31, 2015 and 2014, respectively, which is included in selling, general and administrative expenses in the accompanying consolidated statement of income. The total compensation cost related to the non-vested awards not yet recognized at March 31, 2015 was approximately $15.3 million and is expected to be recognized ratably over the remaining requisite service period.

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

	Number of Non-vested Units		Weighted Average Grant Date Fair Value
Outstanding non-vested units at December 31, 2014	532,748		$	39.29
Granted	17,870		39.21
Vested	(2,708	)	37.18
Forfeited	—		—
Outstanding non-vested units at March 31, 2015	547,910		$	39.30

Repurchase Program

In May 2009, the board of directors of the General Partner authorized the repurchase of the Partnership’s common units (the “Repurchase Program”) for the purpose of meeting the General Partner’s anticipated obligations to deliver common units under the LTIP and meeting the General Partner’s obligations under existing employment agreements and other employment related obligations of the General Partner (collectively, the “General Partner’s Obligations”). The General Partner is currently authorized to acquire up to 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 791,792 common units pursuant to the Repurchase Program for approximately $23.3 million, of which approximately $2.4 million was purchased during the three months ended March 31, 2015.

Common units outstanding as reported in the accompanying consolidated financial statements at March 31, 2015 and December 31, 2014 excluded 453,219 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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Note 13. 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 forwards, swaps and options.

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.

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.

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Note 13. Fair Value Measurements (continued)

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 March 31, 2015 and December 31, 2014 (in thousands):

	Fair Value as of March 31, 2015
	Level 1		Level 2			Level 3			Cash Collateral Netting (2)			Total
Assets:
Forward derivative contracts (1)	$	—	$	50,375		$	7,095		$	—		$	57,470
Foreign currency derivatives	—		27			—			—			27
Interest rate cap	—		17			—			—			17
Exchange-traded/cleared derivative instruments (2)	78,249		—			—			(44,512		)	33,737
Pension plans	17,316		—			—			—			17,316
Total assets	$	95,565	$	50,419		$	7,095		$	(44,512	)	$	108,567

Liabilities:
Forward derivative contracts (1)	$	—	$	(25,583	)	$	(21,984	)	$	—		$	(47,567	)
Swap agreements and options	—		(705		)	—			—			(705		)
Interest rate swaps	—		(6,649		)	—			—			(6,649		)
Total liabilities	$	—	$	(32,937	)	$	(21,984	)	$	—		$	(54,921	)

	Fair Value as of December 31, 2014
	Level 1		Level 2			Level 3			Cash Collateral Netting (2)			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 plans	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.

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Note 13. Fair Value Measurements (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 and fair value of the Partnership’s 6.25% Notes, estimated by observing market trading prices of the 6.25% Notes, were as follows (in thousands):

	March 31, 2015				December 31, 2014
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value

6.25% Notes	$	375,000	$	365,411	$	375,000	$	358,594

The carrying value of the Partnership’s 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 Note 5.

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 Partnership’s Level 1 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 Partnership’s Level 1 exchange-traded/cleared derivative instruments were based on quoted process obtained from the NYMEX and CME. The fair values of the Partnership’s Level 1 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 Partnership’s Level 2 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 Partnership’s Level 2 derivative commodity contracts were derived from published and quoted NYMEX, CME, New York Harbor and third-party pricing information for the underlying instruments using market approaches. The fair value of the Partnership’s Level 2 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 Partnership’s Level 2 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 Level 2 inputs during the three months ended March 31, 2015.

Level 3 Information

The values of the Partnership’s Level 3 derivative contracts were calculated using market approaches based on a combination of observable and unobservable market inputs, including published and quoted NYMEX, CME, 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 Partnership’s Level 3 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 were $7.45 to $10.75 per barrel for the three months ended March 31, 2015 and 2014, respectively. Gains and losses recognized in earnings (or changes in net assets) are disclosed in Note 5.

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Note 13. Fair Value Measurements (continued)

Sensitivity of the fair value measurement to changes in the significant unobservable inputs is as follows:

Significant Unobservable Input	Position	Change to Input	Impact on Fair Value 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 Level 3 in the fair value hierarchy at March 31, 2015 (in thousands):

Fair value at December 31, 2014	$	(25,523	)
Reclass of Level 2 inputs	—
Realized and unrealized gains (losses) recorded in cost of sales	10,634
Fair value at March 31, 2015	$	(14,889	)

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 period, accounting guidance requires quantitative disclosures about the fair value measurements separately for each major category. See Note 2 for acquired assets and liabilities measured on a non-recurring basis during the quarter ended March 31, 2015.

Note 14. Income Taxes

Section 7704 of the Internal Revenue Code provides that publicly-traded partnerships are, as a general rule, taxed as corporations. However, an exception, referred to as the “Qualifying Income Exception,” exists under Section 7704(c) with respect to publicly-traded partnerships of which 90% or more of the gross income for every taxable year consists of “qualifying income.” Qualifying income includes income and gains derived from the transportation, storage and marketing of refined petroleum products and crude oil 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.

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Note 14. Income Taxes (continued)

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.

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, the Partnership believes that the recorded deferred tax assets will be realized.

Note 15. 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 11 included herein, the Partnership is not aware of any significant legal or governmental proceedings against it, or contemplated to be brought against it. The Partnership maintains insurance policies with insurers in amounts and with coverage and deductibles as its general partner believes are reasonable and prudent. However, the Partnership can provide no assurance that this insurance will be adequate to protect it from all material expenses related to potential future claims or that these levels of insurance will be available in the future at economically acceptable prices.

Other

On March 26, 2015, the Partnership received a Notice of Non-Compliance (“NON”) from the Massachusetts Department of Environmental Protection (“DEP”) with respect to its terminal located at 101 and 186 Lee Burbank Highway, Revere, Massachusetts (the “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, which includes modifications to the storm water management system at the 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 $12.0 million. 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 March 24, 2015. The Partnership believes it has meritorious positions and intends to vigorously pursue a favorable result in connection with this dispute.

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Note 15. Legal Proceedings (continued)

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 Clean Air Act. The suit, filed in the United States District Court for the district of Oregon, alleges that Cascade Kelly is operating without the proper permit under the applicable rules. The lawsuit seeks penalties, injunctive relief and reimbursement of attorneys’ fees. The Partnership has meritorious defenses to the lawsuit and will vigorously contest the actions taken by the Plaintiffs.

On May 16, 2014, the Partnership received a subpoena from the Securities and Exchange Commission requesting information for relevant time periods primarily relating to the Partnership’s accounting for Renewable Identification Numbers and the restatements of its consolidated financial statements as of and for the quarters ended March 31, 2013, June 30, 2013 and September 30, 2013. The Partnership intends to continue to cooperate fully with, and has produced responsive materials to, the SEC.

On December 30, 2013, the Oregon Department of Environmental Quality (“ODEQ”) unilaterally modified (the “Modification”) an air emissions permit held by Cascade Kelly, which covers both the production of ethanol and transshipping of crude oil by the Partnership’s bio-refinery in Clatskanie, Oregon (the “Combined Permit”). This Modification proposed to limit the number of trains carrying crude oil that the bio-refinery can receive as part of the Partnership’s transloading operations. The Partnership submitted a request for a hearing to contest the Modification, which allowed the Combined Permit to remain in effect pending this appeal. On March 27, 2014, ODEQ issued the Partnership a civil penalty assessment (“CPA”) of $117,292 claiming that the Partnership was in violation of the Combined Permit because the Partnership may have received more crude oil than the Combined Permit allows. The Partnership had meritorious defenses to the Modification and the allegations in the CPA. The Partnership denies any wrong doing but resolved the dispute related to the Modifications and the CPA with ODEQ in February 2015. As part of the settlement with ODEQ, the Partnership will pay a total of $102,292.

Separately, in August 2013, the Partnership submitted an application to ODEQ for a separate air emissions permit covering the transloading of crude oil by the bio-refinery (the “New Permit”). On August 17, 2014, ODEQ issued the New Permit to Cascade Kelly authorizing the storage and transloading of up to 1.8 billion gallons of crude oil or ethanol. The Partnership entered into a settlement with ODEQ in January 2015 to resolve all claims related to the Modification and the PEN. In exchange for the Partnership’s agreement to pay a total civil penalty of $102,292, ODEQ has agreed to withdraw the Modification and to resolve the PEN in its entirety. This settlement will allow the Partnership to continue to operate the Cascade Kelly terminal crude oil operations according to the requirements of the New Permit issued in August 2014.

The Partnership received from the EPA, by letters dated November 2, 2011 and March 29, 2012, reporting requirements and testing orders (collectively, the “Requests for Information”) for information under the Clean Air Act. The Requests for Information were part of an EPA investigation to determine whether the Partnership has violated sections of the Clean Air Act at certain of its terminal locations in New England with respect to residual oil and asphalt. On June 6, 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 anticipates further negotiations with the EPA. While the Partnership does not believe that a material violation has occurred, and its 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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(Unaudited)

Note 16. Changes in Accumulated Other Comprehensive Loss

The following table presents the changes in accumulated other comprehensive loss by component for the three months ended March 31, 2015 (in thousands):

	Pension Plan			Derivatives			Total
Balance at December 31, 2014	$	(5,547	)	$	(7,705	)	$	(13,252	)
Other comprehensive income before reclassifications of gain (loss)	109			183			292
Amount of gain (loss) reclassified from accumulated other comprehensive income	(18		)	—			(18		)
Total comprehensive income	91			183			274
Balance at March 31, 2015	$	(5,456	)	$	(7,522	)	$	(12,978	)

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 17. New Accounting Standards

Accounting Standards or Updates Recently Adopted

In April 2014, the FASB issued Accounting Standards Update (“ASU”) No. 2014-08, “Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity,” which includes amendments that change the requirements for reporting discontinued operations and require additional disclosures about discontinued operations. Under the new guidance, only disposals representing a strategic shift in operations that has a major effect on the entity’s operations and financial results should be presented as discontinued operations. Additionally, this standard requires expanded disclosures about discontinued operations that will provide financial statement users with more information about the assets, liabilities, income and expenses of discontinued operations. This standard is effective prospectively for fiscal years beginning after December 15, 2014, with early adoption permitted. The Partnership adopted this standard which did not have a material impact on its consolidated financial statements.

Accounting Standards or Updates Not Yet Effective

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. Early adoption is permitted. The Partnership does not expect the impact of adopting this standard to be material to the Partnership’s 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. This standard is effective for fiscal years beginning after December 15, 2016. The Partnership is currently evaluating the new guidance to determine the impact it will have on its consolidated financial statements.

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Note 17. New Accounting Standards (continued)

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

Note 18. Subsequent Events

On April 9, 2015, the Partnership, as Buyer, entered into a Sale and Purchase Agreement (the “Purchase Agreement”) with 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”), as Seller. Under the terms of the Purchase Agreement, the Partnership will acquire 97 primarily Mobil and Exxon branded retail gasoline stations and seven dealer supply contracts in New York City and Prince George’s County, Maryland, along with certain related supply, franchise agreements, third party leases and other assets associated with the operations (collectively, the “Acquired Assets”) for a cash purchase price of approximately $156.0 million, subject to certain post-closing adjustments related to the Acquired Assets at the time of closing (the “CPG Acquisition”). Of the 97 locations, 18 are fee properties and the balance are the subject of long term leases.

The Purchase Agreement provides that the closing will take place on or before June 1, 2015, subject to a one-time extension not to exceed 30 days, if required in connection with satisfying certain closing conditions, including filing under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (“HSR”) (the “Closing Date”). Closing of the CPG Acquisition is conditioned upon the satisfaction or waiver of customary closing conditions, including HSR approval, certain third party rights of first refusal and delivery of all items required by the Purchase Agreement.

The Purchase Agreement contains customary representations and warranties and covenants by each of the parties. Among other covenants, during the period between the execution of the Purchase Agreement and the closing of the CPG Acquisition, Capitol Petroleum Group has agreed to conduct its business in substantially the same manner previously conducted and not to engage in certain types of activities and transactions. At closing, subject to the terms and conditions set forth in the Purchase Agreement, the Partnership will assume certain liabilities and obligations of Capitol Petroleum Group related to the Acquired Assets. The Partnership expects to finance the CPG Acquisition with borrowings under its revolving credit facility.

The Partnership will account for this transaction as a business combination, and management is currently in the process of evaluating the preliminary purchase price accounting. The Partnership intends to engage a third-party valuation firm to assist in the valuation of the Acquired Assets and possible intangible assets. The operations of Acquired Assets are expected to be reported within the Partnership’s GDSO segment upon closing.

On April 22, 2015, the board of directors of the General Partner declared a quarterly cash distribution of $0.68 per unit ($2.72 per unit on an annualized basis) for the period from January 1, 2015 through March 31, 2015. On May 15, 2015, the Partnership will pay this cash distribution to its unitholders of record as of the close of business on May 6, 2015.

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(Unaudited)

Note 19. Supplemental Guarantor Condensed Consolidating Financial Statements

The Partnership’s wholly-owned subsidiaries other than GLP Finance Corp. are guarantors of senior notes issued by the Partnership and GLP Finance Corp. As such, the Partnership is subject to the requirements of Rule 3-10 of Regulation S-X of the Securities and Exchange Commission 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 March 31, 2015 and December 31, 2014, the Condensed Consolidating Statements of Income for the three months ended March 31, 2015 and 2014 and the Condensed Consolidating Statements of Cash Flows for the three months ended March 31, 2015 and 2014 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Condensed Consolidating Balance Sheet

March 31, 2015

(In thousands)

	Issuer		Non-
	Guarantor		Guarantor
	Subsidiaries		Subsidiary		Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	2,469	$	3,876	$	—		$	6,345
Accounts receivable, net	409,579		1,302		—			410,881
Accounts receivable—affiliates	4,059		1,045		(1,259		)	3,845
Inventories	371,627		—		—			371,627
Brokerage margin deposits	33,737		—		—			33,737
Derivative assets	57,470		—		—			57,470
Prepaid expenses and other current assets	73,504		619		—			74,123
Total current assets	952,445		6,842		(1,259		)	958,028
Property and equipment, net	1,128,262		45,821		—			1,174,083
Intangible assets, net	79,772		277		—			80,049
Goodwill	215,924		86,063		—			301,987
Other assets	54,637		—		—			54,637
Total assets	$	2,431,040	$	139,003	$	(1,259	)	$	2,568,784
Liabilities and partners’ equity
Current liabilities:
Accounts payable	$	306,937	$	583	$	—		$	307,520
Accounts payable - affiliates	1,045		214		(1,259		)	—
Working capital revolving credit facility—current portion	125,400		—		—			125,400
Environmental liabilities—current portion	3,085		—		—			3,085
Trustee taxes payable	90,183		—		—			90,183
Accrued expenses and other current liabilities	60,394		524		—			60,918
Derivative liabilities	48,272		—		—			48,272
Total current liabilities	635,316		1,321		(1,259		)	635,378
Working capital revolving credit facility—less current portion	150,000		—		—			150,000
Revolving credit facility	517,400		—		—			517,400
Senior notes	368,316		—		—			368,316
Environmental liabilities—less current portion	72,186		—		—			72,186
Deferred tax liability	120,708		—		—			120,708
Other long-term liabilities	61,811		—		—			61,811
Total liabilities	1,925,737		1,321		(1,259		)	1,925,799
Partners’ equity
Global Partners LP equity	505,303		88,474		—			593,777
Noncontrolling interest	—		49,208		—			49,208
Total partners’ equity	505,303		137,682		—			642,985
Total liabilities and partners’ equity	$	2,431,040	$	139,003	$	(1,259	)	$	2,568,784

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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	$	1,478	$	2,678	$	1,082		$	5,238
Accounts receivable, net	455,603		1,307		820			457,730
Accounts receivable—affiliates	3,222		820		(139		)	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	55,881		634		—			56,515
Total current assets	954,021		5,439		1,763			961,223
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	50,723		—		—			50,723
Total assets	$	1,897,014	$	141,200	$	1,763		$	2,039,977
Liabilities and partners’ equity
Current liabilities:
Accounts payable	$	454,267	$	1,671	$	681		$	456,619
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	703,305		3,505		681			707,491
Working capital revolving credit facility—less current portion	100,000		—		—			100,000
Revolving credit facility	133,800		—		—			133,800
Senior notes	368,136		—		—			368,136
Environmental liabilities—less current portion	34,462		—		—			34,462
Deferred tax liability	14,078		—		—			14,078
Other long-term liabilities	45,854		—		—			45,854
Total liabilities	1,399,635		3,505		681			1,403,821
Partners’ equity
Global Partners LP equity	497,379		88,481		1,082			586,942
Noncontrolling interest	—		49,214		—			49,214
Total partners’ equity	497,379		137,695		1,082			636,156
Total liabilities and partners’ equity	$	1,897,014	$	141,200	$	1,763		$	2,039,977

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GLOBAL PARTNERS LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Condensed Consolidating Statement of Income

Three Months Ended March 31, 2015

(In thousands)

	(Issuer)			Non-
	Guarantor			Guarantor
	Subsidiaries			Subsidiary			Eliminations			Consolidated

Sales	$	2,975,185		$	8,050		$	(4,119	)	$	2,979,116
Cost of sales	2,812,472			2,205			(4,119		)	2,810,558
Gross profit	162,713			5,845			—			168,558

Costs and operating expenses:
Selling, general and administrative expenses	48,026			760			—			48,786
Operating expenses	66,317			2,339			—			68,656
Amortization expense	2,586			2,755			—			5,341
Loss on asset sales	437			—			—			437
Total costs and operating expenses	117,366			5,854			—			123,220

Operating income	45,347			(9		)	—			45,338

Interest expense	(13,958		)	(5		)	—			(13,963		)

Income before income tax expense	31,389			(14		)	—			31,375

Income tax expense	(966		)	—			—			(966		)

Net income	30,423			(14		)	—			30,409

Net income attributable to noncontrolling interest	—			6			—			6

Net income attributable to Global Partners LP	30,423			(8		)	—			30,415

Less: General partner’s interest in net income, including incentive distribution rights	2,179			—			—			2,179

Limited partners’ interest in net income	$	28,244		$	(8	)	$	—		$	28,236

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GLOBAL PARTNERS LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Condensed Consolidating Statement of Income

Three Months Ended March 31, 2014

(In thousands)

	(Issuer)			Non-
	Guarantor			Guarantor
	Subsidiaries			Subsidiary			Eliminations			Consolidated

Sales	$	5,114,874		$	8,145		$	(6,091	)	$	5,116,928
Cost of sales	4,962,534			1,461			(6,091		)	4,957,904
Gross profit	152,340			6,684			—			159,024

Costs and operating expenses:
Selling, general and administrative expenses	36,543			755			—			37,298
Operating expenses	45,180			2,772			—			47,952
Amortization expense	1,773			2,755			—			4,528
Loss on asset sales	663			—			—			663
Total costs and operating expenses	84,159			6,282			—			90,441

Operating income	68,181			402			—			68,583

Interest expense	(11,066		)	(41		)	—			(11,107		)

Income before income tax expense	57,115			361			—			57,476

Income tax expense	(322		)	—			—			(322		)

Net income	56,793			361			—			57,154

Net income attributable to noncontrolling interest	—			(144		)	—			(144		)

Net income attributable to Global Partners LP	56,793			217			—			57,010

Less: General partner’s interest in net income, including incentive distribution rights	1,508			—			—			1,508

Limited partners’ interest in net income	$	55,285		$	217		$	—		$	55,502

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Condensed Consolidating Statement Cash Flows

Three Months Ended March 31, 2015

(In thousands)

	(Issuer)			Non-
	Guarantor			Guarantor
	Subsidiaries			Subsidiary			Consolidated
Cash flows from operating activities
Net cash (used in) provided by operating activities	$	(117,146	)	$	3,231		$	(113,915	)
Cash flows from investing activities
Acquisitions	(405,478		)	—			(405,478		)
Capital expenditures	(12,712		)	(1,333		)	(14,045		)
Proceeds from sale of property and equipment	1,044			—			1,044
Net cash used in investing activities	(417,146		)	(1,333		)	(418,479		)
Cash flows from financing activities
Borrowings from on working capital revolving credit facility	175,400			—			175,400
Borrowings from revolving credit facility	383,600			—			383,600
Payments on line of credit	—			(700		)	(700		)
Repurchase of common units	(2,442		)	—			(2,442		)
Noncontrolling interest capital contribution	1,880			—			1,880
Distribution to noncontrolling interest	(1,880		)	—			(1,880		)
Distributions to partners	(22,357		)	—			(22,357		)
Net cash provided by (used in) financing activities	534,201			(700		)	533,501
Cash and cash equivalents
(Decrease) increase in cash and cash equivalents	(91		)	1,198			1,107
Cash and cash equivalents at beginning of period	2,560			2,678			5,238
Cash and cash equivalents at end of period	$	2,469		$	3,876		$	6,345

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Condensed Consolidating Statement Cash Flows

Three Months Ended March 31, 2014

(In thousands)

	(Issuer)			Non-
	Guarantor			Guarantor
	Subsidiaries			Subsidiary			Consolidated
Cash flows from operating activities
Net cash provided by operating activities	$	48,362		$	4,784		$	53,146
Cash flows from investing activities
Capital expenditures	(12,301		)	(774		)	(13,075		)
Proceeds from sale of property and equipment	1,746			—			1,746
Net cash used in investing activities	(10,555		)	(774		)	(11,329		)
Cash flows from financing activities
Payments on working capital revolving credit facility	(20,200		)	—			(20,200		)
Noncontrolling interest capital contribution	2,400			—			2,400
Distribution to noncontrolling interest	(2,400		)	—			(2,400		)
Distributions to partners	(17,770		)	—			(17,770		)
Net cash used in financing activities	(37,970		)	—			(37,970		)
Cash and cash equivalents
(Decrease) increase in cash and cash equivalents	(163		)	4,010			3,847
Cash and cash equivalents at beginning of period	8,371			846			9,217
Cash and cash equivalents at end of period	$	8,208		$	4,856		$	13,064

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Item 2. 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 Quarterly Report on Form 10-Q.

Forward-Looking Statements

Some of the information contained in this Quarterly Report on Form 10-Q may contain forward-looking statements. Forward-looking statements include, without limitation, any statement that may project, indicate or imply future results, events, performance or achievements, and may contain the words “may,” “believe,” “should,” “could,” “expect,” “anticipate,” “plan,” “intend,” “estimate,” “continue,” “will likely result,” or other similar expressions. In addition, any statement made by our management concerning future financial performance (including future revenues, earnings or growth rates), ongoing business strategies or prospects, and possible actions by us are also forward-looking statements. Although we believe these forward-looking statements are reasonable as and when made, there may be events in the future that we are not able to predict accurately or control, and there can be no assurance that future developments affecting our business will be those that we anticipate. Additionally, all statements concerning our expectations regarding future operating results are based on current forecasts for our existing operations and do not include the potential impact of any future acquisitions. The factors listed under Part I, Item 1A, “Risk Factors,” in our Annual Report on Form 10-K for the year ended December 31, 2014, as well as any cautionary language in this report, describe the known material risks, uncertainties and events that may cause our actual results to differ materially from the expectations we describe in our forward-looking statements. Additional factors or events that may emerge from time to time, or those that we currently deem to be immaterial, could cause our actual results to differ, and it is not possible for us to predict all of them. You are cautioned not to place undue reliance on the forward-looking statements contained herein. The following factors are among those that may cause actual results to differ materially and adversely from our forward-looking statements:

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

· A significant decrease in demand for the products we sell in the areas we serve could reduce our ability to make distributions to our unitholders.

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

· 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 decrease in cash available for distribution to our unitholders.

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

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

· Our crude oil sales could be adversely affected by, among other things, unanticipated changes in the crude oil market structure, grade differentials and volatility (or lack thereof), implementation of regulations that adversely impact the market for delivering crude oil 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.

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

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

· Our risk management policies cannot eliminate all commodity risk or 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.

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

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

· We are exposed to trade credit risk 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 indenture 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 indenture and any future financing agreements could impact our access to bank loans and other sources of financing and restrict our ability to finance future operations or capital needs or to engage in, expand or pursue our business activities.

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

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

· Adverse developments in the areas where we conduct our business could reduce our ability to make distributions to our unitholders.

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

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

· Our businesses are subject to both federal and state environmental and non-environmental regulations which could have a material adverse effect on such businesses.

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

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

Additional information about risks and uncertainties that could cause actual results to differ materially from forward-looking statements is contained in Part I, Item 1A, “Risk Factors,” in our Annual Report on Form 10-K for the year ended December 31, 2014 and Part II, Item 1A, “Risk Factors,” in this Quarterly Report on Form 10-Q.

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We expressly disclaim any obligation or undertaking to update these statements to reflect any change in our expectations or beliefs or any change in events, conditions or circumstances on which any forward-looking statement is based, other than as required by federal and state securities laws. All forward-looking statements included in this Quarterly Report on Form 10-Q and all subsequent written or oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these cautionary statements.

Overview

General

We are a midstream logistics and marketing company that engages in the purchasing, selling and logistics of transporting petroleum and related products, including domestic and Canadian crude oil, gasoline and gasoline blendstocks (such as ethanol and naphtha), 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 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 March 31, 2015, we had a portfolio of 1,447 owned, leased and/or supplied gasoline stations, including 287 convenience stores, primarily in the Northeast.

Collectively, we sold approximately $2.9 billion of refined petroleum products, renewable fuels, crude oil, natural gas and propane for the three months ended March 31, 2015. In addition, we had other revenues of approximately $83.1 million, primarily from convenience store sales at our directly operated stores and rental income from dealer leased or commission agent leased gasoline stations.

We base our pricing on spot prices, fixed prices or indexed prices and routinely use the New York Mercantile Exchange (“NYMEX”) and Chicago Mercantile Exchange (“CME”), IntercontinentalExchange (“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.

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 branded and unbranded gasoline customers and other resellers of transportation fuels. 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 distillate products 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 either to be used for bulk trading purposes or for blending with gasoline through our terminal system. A RIN is a renewable identification number associated with government-mandated renewable fuel standards. To evidence that the required volume of renewable fuel is blended with gasoline, obligated parties must retire sufficient RINs to cover their Renewable Volume Obligation (“RVO”). Our Environmental Protection Agency (“EPA”) obligations relative to renewable fuel reporting are largely limited to the foreign gasoline that we may choose to import.

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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 convenience stores, rental income from gasoline stations leased to dealers or commissioned agents and sundry (car wash sales, lottery and ATM commissions).

As of March 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		287
Commissioned Agents		269
Lessee Dealers		211
Contract Dealers		680
Total		1,447

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 three months ended March 31, 2015 and 2014, 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 and gasoline blendstocks during the late spring and summer months than during the fall and winter. Travel and recreational activities are typically higher in these months in the geographic areas in which we operate, increasing the demand for gasoline and gasoline blendstocks that we distribute. Therefore, our volumes in gasoline and gasoline blendstocks are typically higher in the second and third quarters of the calendar year. As demand for some of our refined petroleum products, specifically home heating oil and residual oil for space heating purposes, is generally greater during the winter months, heating oil and residual oil sales are generally higher during the first and fourth quarters of the calendar year. These factors may result in 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 and crude oil, and increases and/or decreases in the prices of these products may adversely impact our financial condition, results of operations and cash available for distribution to our unitholders and the amount of borrowing available for working capital under our credit agreement Results from our purchasing, storing, terminalling, transporting and selling operations are influenced by prices for refined petroleum products, renewable fuels and crude oil, pricing volatility and the market for such products. Prices in the overall forward market for these products may affect our financial condition, results of operations and cash available for distribution to our unitholders. Our margins can be significantly impacted by the forward product pricing curve, often referred to as the futures market. We typically hedge our exposure to petroleum product and renewable fuel price moves with futures contracts and, to a lesser extent, swaps. In markets where futures prices are higher than current prices, referred to as contango, we may use our storage capacity to improve our margins by storing products we have purchased at lower prices in the current market for delivery to customers

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at higher prices in the future. In markets where futures prices are lower than current prices, referred to as backwardation, inventories can depreciate in value and hedging costs are more expensive. For this reason, in these backward markets, we attempt to reduce our inventories in order to minimize these effects. When prices for the products we sell rise, some of our customers may have insufficient credit to purchase supply from us at their historical purchase volumes, and their customers, in turn, may adopt conservation measures which reduce consumption, thereby reducing demand for product. Furthermore, when prices increase rapidly and dramatically, we may be unable to promptly pass our additional costs on to our customers, resulting in lower margins 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.

· We commit substantial resources to pursuing acquisitions, although there is no certainty that we will successfully complete any acquisitions or receive the economic results we anticipate from completed acquisitions. We are continuously engaged in discussions with potential sellers and lessors of existing (or suitable for development) terminalling, storage, logistics and/or marketing assets, including gasoline stations, and related businesses. Our growth largely depends on our ability to make accretive acquisitions and/or accretive development projects. We may be unable to execute such accretive transactions for a number of reasons, including, but not limited to, the following: (1) we are unable to identify attractive transaction candidates or negotiate acceptable terms; (2) we are unable to obtain financing for such transactions on economically acceptable terms; or (3) we are outbid by competitors. In addition, we may consummate transactions that at the time of consummation we believe will be accretive but that ultimately may not be accretive. If any of these events were to occur, our future growth and ability to increase distributions could be limited. We can give no assurance that our 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 rail and marine transportation services for a substantial portion of our logistics business in transporting the products we sell. A disruption in rail and marine transportation services could have an adverse effect on our financial condition, results of operations and cash available for distribution to our unitholders. Hurricanes, flooding and other severe weather conditions could cause a disruption in the transportation services we depend 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 our 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.

· Our gasoline and gasoline blendstocks 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 and gasoline blendstocks during the late spring and summer months than during the fall and winter. Travel and recreational activities are typically higher in these months in the geographic areas in which we operate, increasing the demand for gasoline and gasoline blendstocks that we distribute. Therefore, our results of operations in gasoline and gasoline blendstocks are can be lower in the first and fourth quarters of the calendar year.

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· 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.

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

· Changes in government usage mandates and tax credits could adversely affect the availability and pricing of ethanol, which could negatively impact our gasoline sales. Future demand for ethanol will be largely dependent upon the economic incentives to blend based upon the relative value of gasoline and ethanol, taking into consideration the EPA’s regulations on the Renewable Fuels Standard (“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 proposed a federal rule proposing 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 rail cars available to transport crude oil and ethanol, which could adversely affect our business. Likewise, some environmental interest groups have recently 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. While these efforts have not succeeded to date, 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) earnings before interest, taxes, depreciation and amortization (“EBITDA”), (4) distributable cash flow, (5) selling, general and administrative expenses (“SG&A”), (6) operating expenses, (7) net income per diluted limited partner unit and (8) degree day.

Product Margin

We view product margin as an important performance measure of the core profitability of our operations. We review product margin monthly for consistency and trend analysis. We define product margin as our product sales minus product costs. Product sales primarily include sales of unbranded and branded gasoline, distillates, residual oil, renewable fuels, crude oil, natural gas and propane, as well as convenience store sales, gasoline station rental income and revenue generated from our logistics activities when it engages 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.

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.

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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.

Net Income Per Diluted Limited Partner Unit

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

Degree Day

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

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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 amounts and cents per gallon):

	Three Months Ended
	March 31,
	2015			2014
Net income attributable to Global Partners LP	$	30,415		$	57,010
Net income per diluted limited partner unit (1)	$	0.92		$	2.03
EBITDA (2)	$	71,841		$	86,494
Distributable cash flow (3)	$	53,710		$	69,520
Wholesale Segment:
Volume (gallons)	1,152,955			1,433,421
Sales
Gasoline and gasoline blendstocks	$	776,143		$	1,994,556
Crude oil (4)	252,110			591,229
Other oils and related products (5)	943,693			1,412,771
Total	$	1,971,946		$	3,998,556
Product margin
Gasoline and gasoline blendstocks	$	29,829		$	49,663
Crude oil (4)	15,257			23,490
Other oils and related products (5)	35,007			34,616
Total	$	80,093		$	107,769
Gasoline Distribution and Station Operations Segment (6):
Volume (gallons)	341,458			236,667
Sales
Gasoline	$	697,334		$	768,904
Station operations (7)	83,075			33,972
Total	$	780,409		$	802,876
Product margin
Gasoline	$	61,699		$	33,280
Station operations (7)(8)	36,723			19,797
Total	$	98,422		$	53,077
Commercial Segment:
Volume (gallons)	126,382			116,265
Sales	$	226,761		$	315,496
Product margin	$	11,558		$	12,329
Combined sales and product margin:
Sales	$	2,979,116		$	5,116,928
Product margin (9)	$	190,073		$	173,175
Depreciation allocated to cost of sales	(21,515		)	(14,151		)
Combined gross profit	$	168,558		$	159,024

GDSO portfolio as of March 31 2015 and 2014,	2015			2014
Company operated	287			124
Commissioned agents	269			212
Lessee dealers	211			199
Contract dealers	680			399
Total GDSO portfolio	1,447			934

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Weather conditions:
Normal heating degree days	2,870	2,870
Actual heating degree days	3,456	3,129
Variance from normal heating degree days	20%	9%
Variance from prior period actual heating degree days	10%	11%

(1) See Note 3 of Notes to Consolidated Financial Statements for net income per diluted limited partner unit calculation.

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

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

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

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

(6) For the three months ended March 31, 2015, the GDSO segment includes the January 2015 acquisition of Warren (see Note 2 of Notes to Consolidated Financial Statements). As the Warren assets were not in place prior to January 2015, the above results are not directly comparable to the prior period.

(7) Station operations primarily consist of convenience stores sales at our directly operated stores and rental income from gasoline stations leased to dealers or commissioned agents.

(8) For the three months ended March 31, 2014, station operations includes the reclass of loss on asset sales from product margin to operating expenses to conform with our current presentation.

(9) Product margin is a non-GAAP financial measure used by management and external users of our consolidated financial statements to assess our business. The table above includes a reconciliation of product margin on a combined basis to gross profit, a directly comparable GAAP measure.

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

	Three Months Ended
	March 31,
	2015			2014
Reconciliation of net income to EBITDA:
Net income	$	30,409		$	57,154
Net loss (income) attributable to noncontrolling interest	6			(144		)
Net income attributable to Global Partners LP	30,415			57,010
Depreciation and amortization, excluding the impact of noncontrolling interest	26,499			18,072
Interest expense, excluding the impact of noncontrolling interest	13,961			11,090
Income tax expense	966			322
EBITDA	$	71,841		$	86,494

Reconciliation of net cash (used in) provided by operating activities to EBITDA:
Net cash (used in) provided by operating activities	$	(113,915	)	$	53,146
Net changes in operating assets and liabilities and certain non-cash items	172,796			23,714
Net cash from operating activities and changes in operating assets and liabilities attributable to noncontrolling interest	(1,967		)	(1,778		)
Interest expense, excluding the impact of noncontrolling interest	13,961			11,090
Income tax expense	966			322
EBITDA	$	71,841		$	86,494

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

	Three Months Ended
	March 31,
	2015			2014
Reconciliation of net income to distributable cash flow:
Net income	$	30,409		$	57,154
Net loss (income) attributable to noncontrolling interest	6			(l44		)
Net income attributable to Global Partners LP	30,415			57,010
Depreciation and amortization, excluding the impact of noncontrolling interest	26,499			18,072
Amortization of deferred financing fees and senior notes discount	1,638			1,388
Amortization of routine bank refinancing fees	(1,121		)	(1,001		)
Maintenance capital expenditures, excluding the impact of noncontrolling interest	(3,721		)	(5,949		)
Distributable cash flow	$	53,710		$	69,520

Reconciliation of net cash (used in) provided by operating activities to distributable cash flow:
Net cash (used in) provided by operating activities	$	(113,915	)	$	53,146
Net changes in operating assets and liabilities and certain non-cash items	172,796			23,714
Net cash from operating activities and changes in operating assets and liabilities attributable to noncontrolling interest	(1,967		)	(1,778		)
Amortization of deferred financing fees and senior notes discount	1,638			1,388
Amortization of routine bank refinancing fees	(1,121		)	(1,001		)
Maintenance capital expenditures, excluding the impact of noncontrolling interest	(3,721		)	(5,949		)
Distributable cash flow	$	53,710		$	69,520

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Consolidated Sales

Our total sales were $3.0 billion and $5.1 billion for the three months ended March 31, 2015 and 2014, respectively, a decrease of $2.1 billion, or 41%, primarily due to a decrease in prices and, to a lesser extent, a decrease in volume sold. Our aggregate volume of product sold was 1.6 billion gallons and 1.8 billion gallons for the three months ended March 31, 2015 and 2014, respectively. The 165 million decrease in volume sold includes a decrease of 280 million gallons in our Wholesale segment, primarily in gasoline and gasoline blendstocks and crude oil. The decrease in volume sold was offset by increases of 105 million gallons in our GDSO segment, primarily as a result of the Warren acquisition, and 10 million gallons in our Commercial segment.

Gross Profit

Our gross profit was $168.6 million and $159.0 million for the three months ended March 31, 2015 and 2014, respectively, an increase of $9.6 million, or 6%, due primarily to the Warren acquisition in January 2015, which significantly contributed to our GDSO segment, and to improved product margins in our GDSO segment from declining gasoline prices during the first quarter of 2015. While our Wholesale product margin in gasoline was positively impacted due to favorable market conditions for the three months ended March 31, 2015, our product margin in gasoline blendstocks was significantly less in the first quarter of 2015 than in the first quarter of 2014. During the first quarter of 2014, severe weather conditions and resulting rail congestion contributed to very favorable market conditions for us in gasoline blendstocks, primarily ethanol, as the availability of railcars for gasoline blendstocks was constrained and certain areas experienced shortages in that product.

Results for Wholesale Segment

Gasoline and Gasoline Blendstocks. Sales from wholesale gasoline and gasoline blendstocks were $0.8 billion and $2.0 billion for the three months ended March 31, 2015 and 2014, respectively. The decrease of $1.2 billion, or 61%, was due to a decrease in volume sold and in gasoline prices during the first quarter.

Our gasoline and gasoline blendstocks product margin was $29.8 million and $49.7 million for the three months ended March 31, 2015 and 2014, respectively, a decrease of $19.9 million, or 40%, primarily in gasoline blendstocks. During the first quarter of 2014, severe weather conditions and resulting rail congestion contributed to very favorable market conditions for us in gasoline blendstocks, primarily ethanol, as the availability of railcars for gasoline blendstocks was constrained and certain areas experienced shortages in that product. Our product margin for gasoline for the first quarter of 2015 was positively impacted compared to the same period in 2014 due to favorable market conditions.

Crude Oil. Crude oil sales and logistics revenues were $0.3 billion and $0.6 billion for the three months ended March 31, 2015 and 2014, respectively, a decrease of $0.3 billion, due to a decline in crude oil prices and to a decrease in volume sold due to, in part, unfavorable market conditions. Our crude oil product margin decreased by $8.2 million, or 35%, to $15.3 million for the first quarter of 2015 from $23.5 million for the first quarter of 2014 primarily for these same reasons and to a $5.0 million reserve related to a customer dispute.

Other Oils and Related Products. Sales from other oils and related products (primarily distillates, residual oil and propane) were $0.9 billion and $1.4 billion for the three months ended March 31, 2015 and 2014, respectively, a decrease of $0.5 million due to a decline in prices. Our product margin from other oils and related products was $35.0 million and $34.6 million for the three months ended March 31, 2015 and 2014, respectively, an increase of $0.4 million. Our product margins related to weather-sensitive products were positively impacted for the first quarter in 2015 and 2014 due to colder weather. Temperatures were 20% colder than normal during the first quarter of 2015 and 9% colder than normal during the first quarter of 2014.

Results for Gasoline Distribution and Station Operations Segment

Gasoline Distribution. Sales from gasoline distribution were $0.7 billion and $0.8 billion for the three months ended March 31, 2015 and 2014, respectively, a $0.1 billion decrease due to a decline in prices which more than offset the increase in volume sold due to the Warren acquisition. Our product margin from gasoline distribution was $61.7 million and $33.3 million for the three months ended March 31, 2015 and 2014, respectively, an increase of $28.4 million, or 85%, due to the Warren acquisition and declining gasoline prices during the first quarter of 2015.

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Station Operations. Our station operations, which include convenience stores sales at our directly operated stores, rental income from gasoline stations leased to dealers or commissioned agents and sundry such as car wash sales, lottery and ATM commissions, collectively generated revenues of $83.1 million and $34.0 million for the three months ended March 31, 2015 and 2014, respectively, an increase of $49.1 million. Our product margin from station operations was $36.7 million and $19.8 million for the three months ended March 31, 2015 and 2014, respectively, an increase of $16.9 million. The increases in sales and product margin were primarily due to the Warren acquisition.

Results for Commercial Segment

Our commercial sales were $0.2 billion and $0.3 billion for the three months ended March 31, 2015 and 2014, respectively, a decrease of $0.1 billion due to a decline in prices which more than offset the increase in volume sold. Our commercial product margin was $11.6 million and $12.3 million for the three months ended March 31, 2015 and 2014, respectively. In our Commercial segment, residual oil accounted for approximately 46% of our total commercial volume sold for each of the three months ended March 31, 2015 and 2014. Distillates, gasoline and natural gas accounted for the remainder of the total commercial sales, volume sold and product margin.

Selling, General and Administrative Expenses

SG&A expenses were $48.8 million and $37.3 million, for the three months ended March 31, 2015 and 2014, respectively, an increase of $11.5 million, or 31%, primarily due to the Warren acquisition. The increase in SG&A expenses was due to an increase in wages and benefits of $6.8 million, primarily due to an increase in headcount, $4.4 million of acquisition costs related to Warren, $2.3 million in a restructuring charge associated with the Warren acquisition and $2.2 million of other SG&A expenses. The increase in SG&A expenses was offset by a decrease of $4.2 million in in incentive compensation.

Operating Expenses

Operating expenses were $68.7 million and $47.9 million for the three months ended March 31, 2015 and 2014, respectively, an increase of $20.8 million, or 43%, primarily due to the Warren acquisition..

Amortization Expense

Amortization expense related to our intangible assets was $5.3 million and $4.5 million for the three months ended March 31, 2015 and 2014, respectively. The increase of $0.8 million was primarily due to the intangible assets acquired in the Warren acquisition

Interest Expense

Interest expense was $14.0 million and $11.1 million for the three months ended March 31, 2015 and 2014, respectively, an increase of $2.9 million, or 26%, primarily to increased interest related to our 6.25% Notes (see Note 6 to Notes to Consolidated Financial Statements) and to additional borrowings related to the Warren acquisition.

Income Tax Expense

Income tax expense of $0.9 million and $0.3 million for the three months ended March 31, 2015 and 2014, 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 ($6,000) and $144,000 for the three months ended March 31, 2015 and 2014, respectively, represents the 40% noncontrolling ownership of the net (loss) income reported.

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Liquidity and Capital Resources

Liquidity

Our primary liquidity needs are to fund our working capital requirements, capital expenditures and distributions and to service our indebtedness. Cash generated from operations and our working capital revolving credit facility provide our primary sources of liquidity.

Working capital increased by $68.9 million to $322.6 million at March 31, 2015 compared to $253.7 million at December 31, 2014, primarily due to a reduction in accounts payable of $149.1 million and in accounts receivable of $46.8 million as we exited the heating season. In addition, due to favorable market conditions, we elected to use our storage capacity to hold more inventory, which increased by $34.8 million and contributed to the increase in our working capital revolving credit facility. The acquisition of Warren also contributed modestly to the increase in working capital. The net increases more than offset a $125.4 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.

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

On April 22, 2015, the board of directors of our general partner declared a quarterly cash distribution of $0.68 per unit ($2.72 per unit on an annualized basis) for the period from January 1, 2015 through March 31, 2015 to our unitholders of record as of the close of business on May 6, 2015. We expect to pay the cash distribution of approximately $23.3 million on May 15, 2015.

Contractual Obligations

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

	Payments due by period
Contractual Obligations	Total		Less than 1 year		1-3 years		4-5 years		More than 5 years
Credit facility obligations (1)	$	564,582	$	14,114	$	475,747	$	74,721	$	—
Senior notes obligations (2)	550,782		23,438		46,875		46,875		433,594
Operating lease obligations (3)	703,026		129,071		278,586		150,322		145,047
Capital lease obligations	607		132		469		6		—
Other long-term liabilities (4)	182,761		13,394		38,004		43,483		87,880
Total	$	2,001,758	$	180,149	$	839,681	$	315,407	$	666,521

(1) Includes principal and interest on our working capital revolving credit facility and our revolving credit facility at March 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. No principal payments are required prior to maturity.

(3) Includes operating lease obligations related to leases for office space and computer equipment, land, terminals and throughputs, gasoline stations, railcars, mobile equipment, access rights, barging agreements and a lease with a related party. In January 2015, we acquired the Revere, Massachusetts terminal we previously leased with a related party, GPC (see Note 2 of Notes to Consolidated Financial Statements).

(4) Includes amounts related to our 15-year brand fee agreement entered into in 2010 with ExxonMobil, amounts related to our pipeline connection agreements with Tesoro Logistics and pension and deferred compensation obligations.

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Capital Expenditures

Our operations require investments to expand, upgrade and enhance existing operations and to meet environmental and operations regulations. We categorize our capital requirements as either maintenance capital expenditures or expansion capital expenditures. Maintenance capital expenditures represent capital expenditures to repair or replace partially or fully depreciated assets to maintain the operating capacity of, or revenues generated by, existing assets and extend their useful lives. Maintenance capital expenditures include expenditures required to maintain equipment reliability, tankage and pipeline integrity and safety and to address certain environmental regulations. We anticipate that maintenance capital expenditures will be funded with cash generated by operations. We had approximately $3.7 million and $5.9 million in maintenance capital expenditures for the three months ended March 31, 2015 and 2014, respectively, which are included in capital expenditures in the accompanying consolidated statements of cash flows. Repair and maintenance expenses associated with existing assets that are minor in nature and do not extend the useful life of existing assets are charged to operating expenses as incurred.

Expansion capital expenditures include expenditures to acquire assets to grow our business or expand our existing facilities, such as projects that increase our operating capacity or revenues by increasing, for example, rail capacity, dock capacity and tankage, diversifying product availability, raze and rebuilds, and new-to-industry gasoline stations and convenience stores and storage flexibility at various terminals and adding terminals. We have the ability to fund our expansion capital expenditures through cash from operations or our credit agreement or by issuing debt securities or additional equity. We had approximately $369.9 million and $7.1 million in expansion capital expenditures for the three months ended March 31, 2015 and 2014, respectively, which are included in capital expenditures in the accompanying consolidated statements of cash flows.

Specifically, for the three months ended March 31, 2015, expansion capital expenditures included approximately $359.6 million in property and equipment associated with the acquisitions of Warren and the Revere Terminal. In addition, we had $10.3 million in expansion capital expenditures which consists of (i) $6.4 million in new site development, rebuilds, expansion and improvements at retail gasoline stations, (ii) $2.6 million in costs associated with our crude oil activities, including, in part, tank construction projects, rail expansion and improvement costs and equipment upgrades and (iii) $1.3 million in other expansion capital expenditures including, in part, investments in information technology and computer and equipment upgrades at various terminals.

For the three months ended March 31, 2014, expansion capital expenditures included approximately $2.6 million in new site development, rebuilds, expansion and improvements at certain retail gasoline stations, $2.1 million in costs associated with our crude oil activities, $1.0 million in costs associated with our propane storage and distribution facility in Albany, New York and $1.4 million in other expansion capital expenditures including, in part, office and computer upgrades at various terminals.

Certain of the $2.6 million and $2.1 million for the three months ended March 31, 2015 and 2014, 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 produce an adverse effect on our borrowing capacity as well as our ability to issue additional common units and/or debt securities.

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Cash Flow

The following table summarizes cash flow activity (in thousands):

	Three Months Ended
	March 31,
	2015			2014
Net cash (used in) provided by operating activities	$	(113,915	)	$	53,146
Net cash used in investing activities	$	(418,479	)	$	(11,329	)
Net cash provided by used in financing activities	$	533,501		$	(37,970	)

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.

Net cash (used in) provided by operating activities was $(113.9) million and $53.1 million for the three months ended March 31, 2015 and 2014, respectively, for a period-over-period increase in cash used in operating activities of $167.0 million, exclusive of acquisitions. The primary drivers of the change include the following (in thousands):

	Three Months Ended						Period over
	March 31,						Period
	2015			2014			Change
Decrease in accounts receivable	$	52,186		$	41,898		$	10,288
(Increase) decrease in inventories	$	(15,614	)	$	112,328		$	(127,942	)
(Decrease) increase in accounts payable	$	(170,646	)	$	(182,076	)	$	11,430

The decreases in accounts receivable and accounts payable were primarily due to the change in activity as we exited the heating season. In addition, due to favorable market conditions, we elected to use our storage capacity to carry increased levels of inventory.

For the three months ended March 31, 2014, the decreases in accounts receivable, inventories and accounts payable primarily reflect the change in activity as we exited the heating season. The decreases in accounts payable and inventories were also due to carrying lower levels of inventory, in part as a result of extreme cold and snow which reduced crude oil activity.

Net cash used in investing activities was $418.5 million for the three months ended March 31, 2015 and included $381.8 million and $23.7 million in cash used to fund the acquisitions of Warren and the Revere Terminal, respectively, $10.3 million in expansion capital expenditures and $3.7 million in maintenance capital expenditures, offset by $1.0 million in proceeds from the sale of property and equipment.

Net cash used in investing activities was $11.3 million for the three months ended March 31, 2014 and included $7.1 million in expansion capital expenditures and $5.9 million in maintenance capital expenditures, offset by $1.7 million in proceeds from the sale of property and equipment.

See “—Capital Expenditures” for a discussion of our expansion capital expenditures for the three months ended March 31, 2015 and 2014.

Net cash provided by financing activities was $533.5 million for the three months ended March 31, 2015 and included $383.6 million in borrowings on our revolving credit facility to fund the acquisitions of Warren and the Revere Terminal, $175.4 million in borrowings on our working credit facility and $1.9 million in capital contributions from our noncontrolling interest at Basin Transload. Net cash provided by financing activities was offset by $22.4 million in cash distributions to our common unitholders and our general partner, $2.4 million in the repurchase of common units pursuant to our repurchase program for future satisfaction of our general partner’s obligations, $1.9 million distributions to our noncontrolling interest at Basin Transload and $0.7 million in net payments on our line of credit related to Basin Transload.

Net cash used in financing activities was $38.0 million for the three months ended March 31, 2014 and included $20.2 million in net payments on our working capital revolving credit facility and $17.8 million in cash distributions to our common unitholders and our general partner.

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Credit Agreement

As of March 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. 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 March 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, for a total credit facility of up to $2.075 billion. We cannot provide assurance, however, that our lending group will agree to fund any request by us for additional amounts in excess of the total available commitments of $1.775 billion.

In addition, the credit agreement includes a swing line pursuant to which Bank of America, N.A., as the swing line lender, may make swing line loans in U.S. Dollars in an aggregate amount equal to the lesser of (a) $50.0 million and (b) the Aggregate WC Commitments (as defined in the credit agreement). Swing line loans will bear interest at the Base Rate (as defined in the credit agreement). The swing line is a sub-portion of the working capital revolving credit facility and is not an addition to the total available commitments of $1.775 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 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 interest rates for the credit agreement were 3.4% and 3.6% for the three months ended March 31, 2015 and 2014, 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 March 31, 2015, we had total borrowings outstanding under the credit agreement of $792.8 million, including $517.4 million outstanding on the revolving credit facility. In addition, we had outstanding letters of credit of $59.8 million. Subject to borrowing base limitations, the total remaining availability for borrowings and letters of credit was $0.9 billion and $1.4 billion at March 31, 2015 and December 31, 2014, respectively.

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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 March 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).

6.25% Senior Notes

On June 19, 2014, we and GLP Finance (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.

Closing of the offering occurred on June 24, 2014.

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.

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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, 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

Line of Credit

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 did not capitalize additional financing fees for the three months ended March 31, 2015 and 2014. Amortization expense of approximately $1.5 million and $1.3 million for the three months ended March 31, 2015 and 2014, respectively, are included in interest expense in the accompanying consolidated statements of income. Unamortized fees are included in other current assets and other long-term assets.

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements.

Critical Accounting Policies and Estimates

Management’s Discussion and Analysis of Financial Condition and Results of Operations discusses our consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of these consolidated financial statements 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 consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results may differ from these estimates under different assumptions or conditions.

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, leases, revenue recognition, derivative financial instruments, valuation of intangibles and other long-lived assets, goodwill, environmental and other liabilities and related party transactions.

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The significant accounting policies and estimates that we have adopted and followed in the preparation of our consolidated financial statements are detailed in Note 2 of Notes to Consolidated Financial Statements, “Summary of Significant Accounting Policies” included in our Annual Report on Form 10-K for the year ended December 31, 2014. There have been no subsequent changes in these policies and estimates that had a significant impact on our financial condition and results of operations for the periods covered in this report.

Recent Accounting Pronouncements

A description and related impact expected from the adoption of certain new accounting pronouncements is provided in Note 17 of Notes to Consolidated Financial Statements included elsewhere in this report.

Item 3. 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 March 31, 2015, we had total borrowings outstanding under our credit agreement of $792.8 million. Please read Item 2, “Management’s Discussion and Analysis—Liquidity and Capital Resources——Credit Agreement” for information on interest rates related to our borrowings. The impact of a 1% increase in the interest rate on this amount of debt would have resulted in an increase in interest expense, and a corresponding decrease in our results of operations, of approximately $7.9 million annually, assuming, however, that our indebtedness remained constant throughout the year.

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 6 of Notes to Consolidated Financial Statements), 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 March 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 Note 5 of Notes to Consolidated Financial Statements for additional information on our derivative instruments.

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Commodity Risk

We hedge our exposure to price fluctuations with respect to refined petroleum products, renewable fuels, crude oil and gasoline blendstocks in storage and expected purchases and sales of these commodities. The derivative instruments utilized consist primarily of 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 statement of income 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 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 regulated exchanges for the commodities that each trades, thereby reducing potential delivery and supply risks. Generally, our practice is to close all exchange positions rather than to make or receive physical deliveries. With respect to other energy products such as ethanol, which may not have a correlated exchange contract, we enter into derivative agreements with counterparties that we believe have a strong credit profile, in order to hedge market fluctuations and/or lock-in margins relative to our commitments.

At March 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):

	Fair Value at		Gain (Loss)
	March 31, 2015		Effect of 10% Price Increase			Effect of 10% Price Decrease
Exchange traded derivative contracts	$	78,249	$	(27,330	)	$	27,330
Forward derivative contracts	9,197		(10,359		)	10,359
	$	87,446	$	(37,689	)	$	37,689

The fair values of the futures contracts are based on quoted market prices obtained from the NYMEX and the CME. The fair value of the swaps and option contracts are estimated based on 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 March 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 $33.7 million at March 31, 2015.

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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 and CME 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 4. 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 and the existence of a material weakness in our internal control over financial reporting (discussed below), and with insufficient time to fully evaluate and test, under sampling standards, the quarterly controls to address the material weakness, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were not effective as of March 31, 2015.

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-Q 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.

Internal Control Over Financial Reporting

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

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. We are putting in place timely controls and developing systems and designing controls to improve the process of the valuation protocol which will enhance the quality of management’s review of these valuations, and once they have been in operation for a sufficient period of time, these actions will be fully tested to determine whether they are operating effectively. Due to having insufficient time to fully evaluate and test, under sampling standards, the quarterly controls, management has determined that we did not maintain effective internal control over financial reporting as of March 31, 2015.

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

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PART II. OTHER INFORMATION

Item 1. 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 and in Note 11 in this Quarterly Report on Form 10-Q, we are not aware of any significant legal or governmental proceedings against us, or contemplated to be brought against us. We maintain insurance policies with insurers in amounts and with coverage and deductibles as our general partner believes are reasonable and prudent. However, we can provide no assurance that this insurance will be adequate to protect us from all material expenses related to potential future claims or that these levels of insurance will be available in the future at economically acceptable prices.

Other

On March 26, 2015, we received a Notice of Non-Compliance (“NON”) from the Massachusetts Department of Environmental Protection (“DEP”) with respect to our terminal located at 101 and 186 Lee Burbank Highway, Revere, Massachusetts (the “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, which includes modifications to the storm water management system at the 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. 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 alleging violations of the Clean Air Act (“CAA”). The suit, filed in the United States District Court for the district of Oregon, alleges that Cascade Kelly is operating without the proper permit under the applicable rules. The lawsuit seeks penalties, injunctive relief and reimbursement of attorneys’ fees. We have meritorious defenses to the lawsuit and will vigorously contest the actions taken by the Plaintiffs.

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.

On December 30, 2013, the Oregon Department of Environmental Quality (“ODEQ”) unilaterally modified (the “Modification”) an air emissions permit held by Cascade Kelly, which covers both the production of ethanol and transshipping of crude oil by our bio-refinery in Clatskanie, Oregon (the “Combined Permit”). This Modification proposed to limit the number of trains carrying crude oil that the bio-refinery can receive as part of our transloading operations. We submitted a request for a hearing to contest the Modification, which allowed the Combined Permit to remain in effect pending this appeal. On March 27, 2014, ODEQ issued us a civil penalty assessment (“CPA”) of $117,292 claiming that we were in violation of the Combined Permit because we may have received more crude oil than the Combined Permit allows. We had meritorious defenses to the Modification and the allegations in the CPA. We deny any wrong doing but resolved the dispute related to the Modifications and the CPA with ODEQ in February 2015. As part of the settlement with ODEQ, we will pay a total of $102,292.

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Separately, in August 2013, we submitted an application to ODEQ for a separate air emissions permit covering the transloading of crude oil by the bio-refinery (the “New Permit”). On August 17, 2014, ODEQ issued the New Permit to Cascade Kelly authorizing the storage and transloading of up to 1.8 billion gallons of crude oil or ethanol. We entered into a settlement with ODEQ in January 2015 to resolve all claims related to the Modification and the PEN. In exchange for our agreement to pay a total civil penalty of $102,292, ODEQ has agreed to withdraw the Modification and to resolve the PEN in its entirety. This settlement will allow us to continue to operate the Cascade Kelly terminal crude oil operations according to the requirements of the New Permit issued in August 2014.

We received from the Environmental Protection Agency (the “EPA”), by letters dated November 2, 2011 and March 29, 2012, reporting requirements and testing orders (collectively, the “Requests for Information”) for information under the 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 anticipate further negotiations with the EPA. 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 1A. Risk Factors

In addition to other information set forth in this report, you should carefully consider the factors discussed in Part I, Item 1A, “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2014, which could materially affect our business, financial condition or future results.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

Issuer Purchases of Equity Securities

The table below provides information with respect to purchases of our common units made by our general partner on our behalf during the quarter ended March 31, 2015:

				Maximum Number (or
			Total Number of	Approximate Dollar
			Units Purchased as	Value) of Units That May
	Total Number	Average	Part of Publicly	Yet Be Purchased
	Of Units	Price Paid	Announced Plans or	Under the Plans or
Period	Purchased	Per Unit($)	Programs(1)	Programs(1)
January 1 – January 31, 2015	—	—	—	—
February 1 – February 28, 2015	—	—	—	—
March 1 – March 31, 2015	65,325	37.35	—	450,635

(1) In May 2009, the board of directors of our general partner authorized the repurchase of our common units for the purpose of meeting our general partner’s anticipated obligations to deliver common units under the Long-Term Incentive Plan (“LTIP”) and meeting the general partner’s obligations under existing employment agreements and other employment related obligations of the general partner. Our general partner is currently authorized to acquire up to 1,242,427 of our common units in the aggregate over an extended period of time, consistent with the general partner’s obligations under the LTIP and employment agreements. Common units may be repurchased from time to time in open market transactions, including block purchases, or in privately negotiated transactions. Such authorized unit repurchases may be modified, suspended or terminated at any time, and are subject to price, economic and market conditions, applicable legal requirements and available liquidity.

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Item 6. Exhibits

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).

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).

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).

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).

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	—	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).

10.1^	—	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).

10.2^	—	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).

10.3^	—	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).

10.4	—	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).

10.5	—	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).

10.6	—	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).

31.1*	—	Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of Global GP LLC, general partner of Global Partners LP.

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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.

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SIGNATURES

Pursuant to the requirements 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: May 8, 2015		By:	/s/ Eric Slifka
			Eric Slifka
			President and Chief Executive Officer
			(Principal Executive Officer)


Dated: May 8, 2015		By:	/s/ Daphne H. Foster
			Daphne H. Foster
			Chief Financial Officer
			(Principal Financial Officer)

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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).

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).

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).

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).

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	—	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).

10.1^	—	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).

10.2^	—	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).

10.3^	—	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).

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Exhibit Number		Description

10.4	—	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).

10.5	—	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).

10.6	—	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).

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.

† Not deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934 or otherwise subject to the liability of that section.