GLOBAL PARTNERS LP - Quarter Report: 2014 June (Form 10-Q)

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 June 30, 2014

	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 27,430,563 common units outstanding as of August 5, 2014.

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TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements	1

Consolidated Balance Sheets as of June 30, 2014 and December 31, 2013	1

Consolidated Statements of Operations for the three and six months ended June 30, 2014 and 2013	2

Consolidated Statements of Comprehensive (Loss) Income for the three and six months ended June 30, 2014 and 2013	3

Consolidated Statements of Cash Flows for the six months ended June 30, 2014 and 2013	4

Consolidated Statement of Partners’ Equity for the six months ended June 30, 2014	5

Notes to Consolidated Financial Statements	6

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	41

Item 3. Quantitative and Qualitative Disclosures about Market Risk	64

Item 4. Controls and Procedures	67

PART II. OTHER INFORMATION	69

Item 1. Legal Proceedings	69

Item 1A. Risk Factors	70

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	70

Item 6. Exhibits	71

SIGNATURES	72

INDEX TO EXHIBITS	73

Table of Contents

Item 1. Financial Statements

GLOBAL PARTNERS LP

CONSOLIDATED BALANCE SHEETS

(In thousands, except unit data)

(Unaudited)

	June 30,			December 31,
	2014			2013
Assets
Current assets:
Cash and cash equivalents	$	16,744		$	9,217
Accounts receivable, net	545,696			686,392
Accounts receivable—affiliates	1,939			1,404
Inventories	490,521			572,806
Brokerage margin deposits	20,175			21,792
Fair value of forward fixed price contracts	29,549			46,007
Prepaid expenses and other current assets	48,541			36,693
Total current assets	1,153,165			1,374,311
Property and equipment, net	811,308			803,636
Intangible assets, net	58,717			67,769
Goodwill	154,078			154,078
Other assets	30,614			28,128
Total assets	$	2,207,882		$	2,427,922
Liabilities and partners’ equity
Current liabilities:
Accounts payable	$	513,836		$	781,119
Working capital revolving credit facility—current portion	175,000			—
Line of credit	3,700			3,700
Environmental liabilities—current portion	3,340			3,377
Trustee taxes payable	95,158			80,216
Accrued expenses and other current liabilities	54,950			65,963
Obligations on forward fixed price contracts	36,833			38,197
Total current liabilities	882,817			972,572
Working capital revolving credit facility—less current portion	132,000			327,000
Revolving credit facility	272,600			434,700
Senior notes	367,787			148,268
Environmental liabilities—less current portion	36,899			37,762
Other long-term liabilities	43,228			44,440
Total liabilities	1,735,331			1,964,742
Partners’ equity
Global Partners LP equity:
Common unitholders (27,430,563 units issued and 27,215,947 outstanding at June 30, 2014 and 27,430,563 units issued and 27,260,747 outstanding at December 31, 2013)	434,675			426,785
General partner interest (0.83% interest with 230,303 equivalent units outstanding at June 30, 2014 and December 31, 2013)	53			(238		)
Accumulated other comprehensive loss	(10,705		)	(11,310		)
Total Global Partners LP equity	424,023			415,237
Noncontrolling interest	48,528			47,943
Total partners’ equity	472,551			463,180
Total liabilities and partners’ equity	$	2,207,882		$	2,427,922

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

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GLOBAL PARTNERS LP

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per unit data)

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013

Sales	$	4,569,620		$	4,771,756		$	9,686,548		$	10,360,946
Cost of sales	4,482,332			4,677,959			9,440,899			10,208,077
Gross profit	87,288			93,797			245,649			152,869

Costs and operating expenses:
Selling, general and administrative expenses	31,673			25,680			68,971			51,343
Operating expenses	51,029			47,367			98,981			90,707
Amortization expense	4,524			4,774			9,052			8,548
Total costs and operating expenses	87,226			77,821			177,004			150,598

Operating income	62			15,976			68,645			2,271

Interest expense	(12,246		)	(10,772		)	(23,353		)	(21,258		)

(Loss) income before income tax (expense) benefit	(12,184		)	5,204			45,292			(18,987		)

Income tax (expense) benefit	(94		)	—			(416		)	1,875

Net (loss) income	(12,278		)	5,204			44,876			(17,112		)

Net income attributable to noncontrolling interest	(441		)	(379		)	(585		)	(130		)

Net (loss) income attributable to Global Partners LP	(12,719		)	4,825			44,291			(17,242		)

Less: General partner’s interest in net (loss) income, including incentive distribution rights	1,033			764			2,541			1,264

Limited partners’ interest in net (loss) income	$	(13,752	)	$	4,061		$	41,750		$	(18,506	)

Basic net (loss) income per limited partner unit	$	(0.50	)	$	0.15		$	1.53		$	(0.68	)

Diluted net (loss) income per limited partner unit	$	(0.50	)	$	0.15		$	1.53		$	(0.68	)

Basic weighted average limited partner units outstanding	27,244			27,394			27,252			27,358

Diluted weighted average limited partner units outstanding	27,244			27,491			27,313			27,358

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

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GLOBAL PARTNERS LP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME

(In thousands)

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013

Net (loss) income	$	(12,278	)	$	5,204		$	44,876		$	(17,112	)
Other comprehensive income:
Change in fair value of cash flow hedges	212			2,049			871			3,522
Change in pension liability	343			1,259			(266		)	2,025
Total other comprehensive income	555			3,308			605			5,547
Comprehensive (loss) income	(11,723		)	8,512			45,481			(11,565		)
Comprehensive income attributable to noncontrolling interest	(441		)	(379		)	(585		)	(130		)
Comprehensive (loss) income attributable to Global Partners LP	$	(12,164	)	$	8,133		$	44,896		$	(11,695	)

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)

	Six Months Ended June 30,
	2014			2013
Cash flows from operating activities
Net income (loss)	$	44,876		$	(17,112	)
Adjustments to reconcile net income (loss) to net provided by in operating activities:
Depreciation and amortization	41,175			34,733
Amortization of deferred financing fees	2,567			3,318
Amortization of senior notes discount	210			158
Bad debt expense	356			2,392
Stock-based compensation expense	1,701			104
Write-off of financing fees	1,626			—
Disposition of property and equipment and other	1,060			(807		)
Changes in operating assets and liabilities, exclusive of business combinations:
Accounts receivable	140,340			112,092
Accounts receivable – affiliate	(535		)	(93		)
Inventories	82,285			294,735
Broker margin deposits	1,617			32,772
Prepaid expenses, all other current assets and other assets	(17,876		)	15,615
Accounts payable	(267,283		)	(158,837		)
Trustee taxes payable	14,942			(15,705		)
Change in fair value of forward fixed price contracts	15,094			21,611
Accrued expenses, all other current liabilities and other long-term liabilities	(12,521		)	2,736
Net cash provided by operating activities	49,634			327,712
Cash flows from investing activities
Acquisitions	—			(185,251		)
Capital expenditures	(44,260		)	(30,069		)
Proceeds from sale of property and equipment	3,405			2,413
Net cash used in investing activities	(40,855		)	(212,907		)
Cash flows from financing activities
Payments on working capital revolving credit facility	(20,000		)	(213,000		)
Payments on revolving credit facility	(162,100		)	(47,300		)
Proceeds from issuance of term loan	—			115,000
Proceeds from senior notes, net of discount	258,903			67,900
Repayment of senior notes	(40,244		)	—
Repurchase of common units	(1,824		)	—
Repurchased units withheld for tax obligations	—			(2,086		)
Noncontrolling interest capital contribution	4,200			1,425
Distribution to noncontrolling interest	(4,200		)	—
Distributions to partners	(35,987		)	(33,048		)
Net cash used in financing activities	(1,252		)	(111,109		)

Increase in cash and cash equivalents	7,527			3,696
Cash and cash equivalents at beginning of period	9,217			5,977
Cash and cash equivalents at end of period	$	16,744		$	9,673

Supplemental information
Cash paid during the period for interest	$	22,130		$	15,544
Non-cash exchange of 6.25% senior notes due 2022	$	110,000		$	—

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)

(Restated) (Unaudited)

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

Balance at December 31, 2013	$	426,785		$	(238	)	$	(11,310	)	$	47,943		$	463,180
Net income	41,750			2,541			—			585			44,876
Noncontrolling interest capital contribution	—			—			—			4,200			4,200
Distribution to noncontrolling interest	—			—			—			(4,200		)	(4,200		)
Other comprehensive income	—			—			605			—			605
Stock-based compensation	1,701			—			—			—			1,701
Distributions to partners	(33,947		)	(2,250		)	—			—			(36,197		)
Dividends on repurchased units	210			—			—			—			210
Repurchase of common units	(1,824		)	—			—			—			(1,824		)
Balance at June 30, 2014	$	434,675		$	53		$	(10,705	)	$	48,528		$	472,551

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 publicly traded Delaware master limited partnership formed in March 2005. As of June 30, 2014, the Partnership had the following wholly owned subsidiaries: Global Companies LLC, Glen Hes Corp., Global Montello Group Corp. (“GMG”), Chelsea Sandwich LLC, Global Energy Marketing LLC, Alliance Energy LLC (“Alliance”), Bursaw Oil LLC, GLP Finance Corp. (“GLP Finance”), Global Energy Marketing II LLC, Global CNG LLC and Cascade Kelly Holdings LLC. Global GP LLC, the Partnership’s general partner (the “General Partner”) manages the Partnership’s operations and activities and employs its officers and substantially all of its personnel, except for its gasoline station and convenience store employees and certain union personnel who are employed by GMG.

The Partnership is a midstream logistics and marketing company. The Partnership is one of the largest distributors of gasoline (including gasoline blendstocks such as ethanol and naphtha), distillates (such as home heating oil, diesel and kerosene), residual oil and renewable fuels to wholesalers, retailers and commercial customers in the New England states and New York. The Partnership also engages in the purchasing, selling and logistics of transporting domestic and Canadian crude oil and other products via rail, establishing a “virtual pipeline” from the mid-continent region of the United States and Canada to the East and West Coasts for distribution to refiners and other customers. The Partnership owns, controls or has access to one of the largest terminal networks of refined petroleum products and renewable fuels in Massachusetts, Maine, Connecticut, Vermont, New Hampshire, Rhode Island, New York, New Jersey and Pennsylvania (collectively, the “Northeast”). The Partnership also owns and controls transload terminals in North Dakota and Oregon that extend its origin-to-destination capabilities. The Partnership is a major multi-brand gasoline distributor and, as of June 30, 2014, had a portfolio of approximately 900 owned, leased and/or supplied gasoline stations primarily in the Northeast. The Partnership receives revenue from retail sales of gasoline, convenience store sales and gasoline station rental income. The Partnership is also a distributor of natural gas and propane.

On February 1, 2013, the Partnership acquired a 60% membership interest in Basin Transload, LLC (“Basin Transload”), and on February 15, 2013, the Partnership acquired 100% of the membership interests in Cascade Kelly Holdings LLC (“Cascade Kelly”). See Note 2.

The General Partner, which holds a 0.83% general partner interest in the Partnership, is owned by affiliates of the Slifka family. As of June 30, 2014, affiliates of the General Partner, including its directors and executive officers and their affiliates, owned 11,604,052 common units, representing a 42.3% limited partner interest.

Basis of Presentation

The financial results of Basin Transload for the five months ended June 30, 2013 and of Cascade Kelly for the four and one-half months ended June 30, 2013 are included in the accompanying statements of operations for the six months ended June 30, 2013. The Partnership consolidates the balance sheet and statement of operations of Basin Transload because the Partnership controls the entity. The accompanying consolidated financial statements as of June 30, 2014 and December 31, 2013 and for the three and six months ended June 30, 2014 and 2013 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, 2013 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 and six months ended June 30, 2014 are not necessarily indicative of the results of operations that will be realized for the entire year ending December 31, 2014. The consolidated balance sheet at December 31, 2013 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, 2013.

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

Noncontrolling Interest

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

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

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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 product sales and logistics revenue as a percentage of total sales for the periods presented:

	Three Months Ended June 30,		Six Months Ended June 30,
	2014	2013	2014	2013
Gasoline sales: gasoline and gasoline blendstocks such as ethanol and naphtha	68%	59%	61%	56%
Crude oil sales and logistics revenue	14%	23%	13%	20%
Distillates (home heating oil, diesel and kerosene), residual oil, natural gas and propane sales	18%	18%	26%	24%
Total	100%	100%	100%	100%

The Partnership had one significant customer, ExxonMobil Corporation (“ExxonMobil”) that accounted for approximately 17% and 16% of total sales for the three and six months ended June 30, 2014, respectively. The Partnership had two significant customers, ExxonMobil and Phillips 66, which accounted for approximately 14% and 16%, respectively, of total sales for the three months ended June 30, 2013 and approximately 14% and 15%, respectively, of total sales for the six months ended June 30, 2013.

Note 2. Business Combinations

Acquisition of Basin Transload LLC

On February 1, 2013, the Partnership acquired a 60% membership interest in Basin Transload, which operates two transloading facilities in Columbus and Beulah, North Dakota for crude oil and other products, with a combined rail loading capacity of 160,000 barrels per day. The purchase price, including expenditures related to certain capital expansion projects, was approximately $91.1 million which the Partnership financed with borrowings under its credit facility.

The acquisition was accounted for using the purchase method of accounting in accordance with the Financial Accounting Standards Board’s (“FASB”) guidance regarding business combinations. The Partnership’s financial statements include the results of operations of its membership interest in Basin Transload subsequent to the acquisition date.

The purchase price for the acquisition was allocated to assets acquired and liabilities assumed based on their estimated fair values. The Partnership then allocated the purchase price in excess of net tangible assets acquired to identifiable intangible assets, based upon a valuation from the Partnership’s third-party valuation firm. Any excess purchase price over the fair value of the net tangible and intangible assets acquired was allocated to goodwill and assigned to the Wholesale reporting unit.

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 2. Business Combinations (continued)

As part of the purchase price allocation, identifiable intangible assets include customer relationships that are being amortized, based on the economic use of the asset, over two years which is consistent with the contractual period of the existing customers. Amortization expense amounted to $2.8 million and $3.0 million for the three months ended June 30, 2014 and 2013, respectively, and $5.5 million and $5.0 million for the six months ended June 30, 2014 and 2013, respectively. The following table presents the estimated remaining amortization expense for intangible assets acquired in connection with the acquisition (in thousands):

2014 (7/1/14-12/31/14)	$	5,510
2015	2,869
Total	$	8,379

Acquisition of Cascade Kelly Holdings LLC

On February 15, 2013, the Partnership acquired 100% of the membership interests in Cascade Kelly, which owns a West Coast crude oil and ethanol facility near Portland, Oregon. The total cash purchase price was approximately $94.2 million which the Partnership funded with borrowings under its credit facility and with proceeds from the issuance of the Partnership’s unsecured 8.0% senior notes due 2018 (see Note 6). Cascade Kelly’s assets include a rail transloading facility serviced by the Burlington Northern Santa Fe Railway, 200,000 barrels of storage capacity, a deepwater marine terminal with access to a 1,200-foot leased dock and the largest ethanol plant on the West Coast. Situated along the Columbia River in Clatskanie, Oregon, the site is located on land leased under a long-term agreement from the Port of St. Helens.

The acquisition was accounted for using the purchase method of accounting in accordance with the FASB’s guidance regarding business combinations. The Partnership’s financial statements include the results of operations of Cascade Kelly subsequent to the acquisition date.

The purchase price for the acquisition was allocated to assets acquired and liabilities assumed based on their estimated fair values. The Partnership then allocated the purchase price in excess of net tangible assets acquired to identifiable intangible assets, if any, based upon on a valuation from the Partnership’s third-party valuation firm. No intangible assets were identified. Any excess purchase price over the fair value of the net tangible assets acquired was allocated to goodwill and assigned to the Wholesale reporting unit.

Supplemental Pro Forma Information

Revenues and net income included in the Partnership’s consolidated operating results for Basin Transload from January 1, 2013 to February 1, 2013, the acquisition date, and for Cascade Kelly from January 1, 2013 to February 15, 2013, the acquisition date, were immaterial. Accordingly, the supplemental pro forma information for the six months ended June 30, 2013 is consistent with the amounts reported in the accompanying statement of operations for the six months ended June 30, 2013.

Note 3. Net (Loss) 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.

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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

Common units outstanding as reported in the accompanying consolidated financial statements at June 30, 2014 and December 31, 2013 excluded 214,616 and 169,816 common units, respectively, held on behalf of the Partnership pursuant to its repurchase program. These units are not deemed outstanding for purposes of calculating net (loss) income per limited partner unit (basic and diluted).

The following table provides a reconciliation of net (loss) income and the assumed allocation of net (loss) income to the limited partners’ interest for purposes of computing net (loss) income per limited partner unit for the three and six months ended June 30, 2014 and 2013 (in thousands, except per unit data):

	Three Months Ended June 30, 2014											Three Months Ended June 30, 2013
Numerator:	Total			Limited Partner Interest			General Partner Interest			IDRs		Total			Limited Partner Interest			General Partner Interest			IDRs
Net (loss) income attributable to Global Partners LP	$	(12,719	)	$	(13,752	)	$	1,033		$	—	$	4,825		$	4,061		$	764		$	—

Declared distribution	$	18,772		$	17,487		$	146		$	1,139	$	16,975		$	16,116		$	135		$	724
Assumed allocation of undistributed net (loss) income	(31,491		)	(31,239		)	(252		)	—		(12,150		)	(12,055		)	(95		)	—
Assumed allocation of net (loss) income	$	(12,719	)	$	(13,752	)	$	(106	)	$	1,139	$	4,825		$	4,061		$	40		$	724

Denominator:
Basic weighted average limited partner units outstanding				27,244											27,394
Dilutive effect of phantom units				—											97
Diluted weighted average limited partner units outstanding				27,244											27,491

Basic net (loss) income per limited partner unit				$	(0.50	)									$	0.15
Diluted net (loss) income per limited partner unit (1)				$	(0.50	)									$	0.15

(1) Basic units were used to calculate diluted net income per limited partner unit for the three months ended June 30, 2014, as using the effects of phantom units would have an anti-dilutive effect on income per limited partner unit.

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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

	Six Months Ended June 30, 2014								Six Months Ended June 30, 2013
Numerator:	Total		Limited Partner Interest		General Partner Interest		IDRs		Total			Limited Partner Interest			General Partner Interest			IDRs
Net income (loss) attributable to Global Partners LP	$	44,291	$	41,750	$	2,541	$	—	$	(17,242	)	$	(18,506	)	$	1,264		$	—

Declared distribution	$	37,095	$	34,632	$	289	$	2,174	$	33,771		$	32,095		$	269		$	1,407
Assumed allocation of undistributed net income (loss)	7,196		7,118		78		—		(51,013		)	(50,601		)	(412		)	—
Assumed allocation of net income (loss)	$	44,291	$	41,750	$	367	$	2,174	$	(17,242	)	$	(18,506	)	$	(143	)	$	1,407

Denominator:
Basic weighted average limited partner units outstanding			27,252									27,358
Dilutive effect of phantom units			61									—
Diluted weighted average limited partner units outstanding			27,313									27,358

Basic net income (loss) per limited partner unit			$	1.53								$	(0.68	)
Diluted net income (loss) per limited partner unit (2)			$	1.53								$	(0.68	)

(2) Basic units were used to calculate diluted net income per limited partner unit for the six months ended June 30, 2013, as using the effects of phantom units would have an anti-dilutive effect on income per limited partner unit.

On April 23, 2014, the board of directors of the General Partner declared a quarterly cash distribution of $0.6250 per unit for the period from January 1, 2014 through March 31, 2014. On July 23, 2014, the board of directors of the General Partner declared a quarterly cash distribution of $0.6375 per unit for the period from April 1, 2014 through June 30, 2014. These declared cash distributions result in incentive distributions to the General Partner, as the holder of the IDRs, and enable the Partnership to exceed its second target level distribution with respect to such IDRs. See Note 8, “Cash Distributions” for further information.

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(Unaudited)

Note 4. Inventories

Except for its convenience store inventory and its Renewable Identification Numbers (“RINs”) inventory, the Partnership hedges substantially all of its inventory, primarily through futures contracts. These futures contracts are entered into when inventory is purchased and are designated as fair value hedges against the inventory on a specific barrel basis. Changes in the fair value of these contracts, as well as the offsetting gain or loss on the hedged inventory item, are recognized in earnings as an increase or decrease in cost of sales. All hedged inventory is valued using the lower of cost, as determined by specific identification, or market. Prior to sale, hedges are removed from specific barrels of inventory, and the then unhedged inventory is sold and accounted for on a first-in, first-out basis. Convenience store inventory and RIN inventory are carried at the lower of historical cost or market.

Inventories consisted of the following (in thousands):

	June 30,		December 31,
	2014		2013
Distillates: home heating oil, diesel and kerosene	$	174,961	$	272,760
Gasoline	141,832		96,539
Gasoline blendstocks	76,419		54,076
Renewable identification numbers (RINs)	8,376		3,186
Crude oil	45,955		87,022
Residual oil	32,138		48,793
Propane and other	2,377		3,443
Convenience store inventory	8,463		6,987
Total	$	490,521	$	572,806

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 $5.9 million and $48.2 million at June 30, 2014 and December 31, 2013, respectively. Negative exchange balances are accounted for as accounts payable and amounted to $42.6 million and $46.7 million at June 30, 2014 and December 31, 2013, respectively. Exchange transactions are valued using current carrying costs.

Note 5. Derivative Financial Instruments

Accounting and reporting guidance for derivative instruments and hedging activities requires that an entity recognize derivatives as either assets or liabilities on the balance sheet and measure the instruments at fair value. Changes in the fair value of the derivative are to be recognized currently in earnings, unless specific hedge accounting criteria are met. The Partnership principally uses derivative instruments to hedge the commodity risk associated with its inventory and product purchases and sales and to hedge variable interest rates associated with the Partnership’s credit facilities.

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(Unaudited)

Note 5. Derivative Financial Instruments (continued)

The following table presents the volume of activity related to the Partnership’s derivative financial instruments at June 30, 2014:

		Units (1)		Unit of Measure
Futures Contracts
Long		14,925		Thousands of barrels
Short		(18,487	)	Thousands of barrels

Natural Gas Contracts
Long		4,562		Thousands of decatherms
Short		(4,706	)	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)	$	12.4		Millions of Canadian dollars
	$	11.6		Millions of U.S. dollars

(1) Number of open positions and gross notional amounts do not quantify risk or represent assets or liabilities of the Partnership, but are used in the calculation of daily cash settlements under the contracts.

(2) All-in forward rate Canadian dollars (“CAD”) $1.067 to USD $1.00.

Fair Value Hedges

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

The Partnership’s futures contracts are settled daily; therefore, there was no corresponding asset or liability on the Partnership’s consolidated balance sheet related to these contracts at June 30, 2014 and December 31, 2013. These contracts remain open until their contract end date. The daily settlement of these futures contracts is accomplished through the use of brokerage margin deposit accounts.

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Note 5. Derivative Financial Instruments (continued)

The following table presents the hedge ineffectiveness from derivatives involved in fair value hedging relationships recognized in the Partnership’s consolidated statements of operations for the three and six months ended June 30, 2014 and 2013 (in thousands):

Amount of Gain (Loss) Recognized in

Income on Derivatives

Location of Gain (Loss)

Three Months Ended

Six Months Ended

Derivatives in Fair Value

Recognized in

June 30,

Hedging Relationships

Income on Derivative

2014

2013

2014

2013

Futures contracts

Cost of sales

6,207

30,486

22,580

20,101

		Amount of Gain (Loss) Recognized in
		Income on Hedged Items
	Location of Gain (Loss)	Three Months Ended						Six Months Ended
Hedged Items in Fair Value	Recognized in	June 30,						June 30,
Hedged Relationships	Income on Hedged Items	2014			2013			2014			2013

Inventories	Cost of sales	$	(5,287	)	$	(29,974	)	$	(21,496	)	$	(19,578	)

Cash Flow Hedges

The Partnership utilizes various interest rate derivative instruments to hedge variable interest rates on its debt. These derivative instruments are designated as cash flow hedges of the underlying debt. To the extent such hedges are effective, the changes in the fair value of the derivative instrument are reported as a component of other comprehensive income (loss) and reclassified into interest expense or interest income in the same period during which the hedged transaction affects earnings.

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

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

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

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

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.

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(Unaudited)

Note 5. Derivative Financial Instruments (continued)

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 is 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 June 30, 2014, 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 following table presents the fair value of the Partnership’s derivative instruments involved in cash flow hedging relationships and their location in the Partnership’s consolidated balance sheets at June 30, 2014 and December 31, 2013 (in thousands):

		June 30,		December 31,
Derivatives Designated as		2014		2013
Hedging Instruments	Balance Sheet Location	Fair Value		Fair Value

Asset derivatives
Interest rate cap (1)	Other assets	$	N/A	$	25

Liability derivatives
Interest rate swaps	Other long-term liabilities	$	8,751	$	9,462

The following table presents the amount of net gains and losses from derivatives involved in cash flow hedging relationships recognized in the Partnership’s consolidated statements of operations and partners’ equity for the three and six months ended June 30, 2014 and 2013 (in thousands):

					Recognized in Income								Recognized in Income
					on Derivatives								on Derivatives
	Amount of Gain (Loss)				(Ineffectiveness Portion				Amount of Gain (Loss)				(Ineffectiveness Portion
	Recognized in Other				and Amount Excluded				Recognized in Other				and Amount Excluded
	Comprehensive Income				from Effectiveness				Comprehensive Income				from Effectiveness
	on Derivatives				Testing)				on Derivatives				Testing)
Derivatives in	Three Months Ended				Three Months Ended				Six Months Ended				Six Months Ended
Cash Flow	June 30,		June 30,		June 30,		June 30,		June 30,		June 30,		June 30,		June 30,
Hedging Relationship	2014		2013		2014		2013		2014		2013		2014		2013

Interest rate collar	$	—	$	611	$	—	$	—	$	—	$	1,226	$	—	$	—
Interest rate swaps	35		1,376		—		—		711		2,239		—		—
Interest rate cap (1)	177		62		—		—		160		57		—		—
Total	$	212	$	2,049	$	—	$	—	$	871	$	3,522	$	—	$	—

(1) The interest rate cap agreement was de-designated as a cash flow hedge in June 2014.

Ineffectiveness related to the interest rate swaps, collar and cap is recognized as interest expense and was immaterial for the three and six months ended June 30, 2014 and 2013. In June 2014, the Partnership elected to de-designate its interest rate cap and discontinued hedge accounting. Except for the amortization of the prepaid interest rate caplets associated with the interest rate cap, totaling $177,000 and $160,000 for the three and six months ended June 30, 2014, respectively, there were no amounts reclassified into earnings for the three and six months ended June 30, 2014 and 2013 under these instruments.

As of June 30, 2014, the remaining unamortized prepaid interest rate caplets were $1.2 million and will be amortized over the remaining life of the interest rate cap which expires in April 2016.

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Note 5. Derivative Financial Instruments (continued)

Other Derivative Activity

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

While the Partnership seeks to maintain a position that is substantially balanced within its product purchase activities, it may experience net unbalanced positions for short periods of time as a result of variances in daily sales and transportation and delivery schedules as well as other logistical issues inherent in the business, such as weather conditions. In connection with managing these positions, maintaining a constant presence in the marketplace, and managing the futures market outlook for future anticipated inventories, which are necessary for its business, the Partnership engages in a controlled trading program for up to an aggregate of 250,000 barrels of products at any one point in time. Any derivatives not involved in a direct hedging activity are marked to market and recognized in the consolidated statement of operations through cost of sales.

The Partnership also markets and sells natural gas by entering into forward purchase commitments for natural gas when it enters into arrangements for the forward sale commitment of product for physical delivery to third-party users. The Partnership reflects the fair value of forward fixed purchase and sales commitments in its consolidated balance sheet. Changes in the fair value of the forward fixed price purchase and sale commitments are recognized in the consolidated statement of income through cost of sales.

During the three and six months ended June 30, 2014 and 2013, the Partnership entered into forward currency contracts to hedge certain foreign denominated (Canadian) product purchases. These forward contracts are not designated and are reflected in the consolidated balance sheets. Changes in the fair values of these forward currency contracts are reflected in cost of sales.

Similar to the futures contracts used by the Partnership to hedge its inventory, the Partnership uses future contracts to economically hedge forward purchase and sale contracts for which the Partnership does not take the normal purchase and sale exemption. Additionally, these futures contracts are settled daily and, accordingly, there was no corresponding asset or liability in the Partnership’s consolidated balance sheets related to these contracts at June 30, 2014 and December 31, 2013. These contracts remain open until their contract end date. The daily settlement of these futures contracts is accomplished through the use of brokerage margin deposit accounts.

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(Unaudited)

Note 5. Derivative Financial Instruments (continued)

The following table summarizes the derivatives not designated by the Partnership as either fair value hedges or cash flow hedges and their respective fair values and location in the Partnership’s consolidated balance sheets at June 30, 2014 and December 31, 2013 (in thousands):

			June 30,		December 31,
		Balance Sheet	2014		2013
Summary of Other Derivatives	Item Pertains to	Location	Fair Value		Fair Value

Asset Derivatives
Forward purchase commitments	Gasoline and Gasoline Blendstocks	(1)	$	3,540	$	14,119
	Distillates	(1)	5,307		2,232
	Residual Oil	(1)	—		34
	Crude Oil	(1)	11,079		13,693
Total forward purchase commitments			19,926		30,078

Forward sales commitments	Gasoline and Gasoline Blendstocks	(1)	3,452		1,486
	Distillates	(1)	107		797
	Residual Oil	(1)	45		655
	Crude Oil	(1)	4,644		383
	Natural Gas	(1)	1,375		12,608
Total forward sales commitments			9,623		15,929
Total fair value of forward fixed price contracts			$	29,549	$	46,007

Liability Derivatives
Forward purchase commitments	Gasoline and Gasoline Blendstocks	(2)	$	5,462	$	3,625
	Distillates	(2)	3,849		1,396
	Residual Oil	(2)	—		990
	Crude Oil	(2)	5,477		2,122
	Natural Gas	(2)	1,388		12,485
Total forward purchase commitments			16,176		20,618

Forward sales commitments	Gasoline and Gasoline Blendstocks	(2)	5,457		10,709
	Distillates	(2)	1,822		3,809
	Crude Oil	(2)	13,378		3,061
Total forward sales commitments			20,657		17,579
Total obligations on forward fixed price contracts and other derivatives			36,833		38,197

Foreign currency forward contract	Foreign Denominated Sales	(3)	170		16
Total liability derivatives			$	37,003	$	38,213

(1) Fair value of forward fixed price contracts

(2) Obligations on forward fixed price contracts

(3) Accrued expenses and other current liabilities

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(Unaudited)

Note 5. Derivative Financial Instruments (continued)

The following table presents the amount of gains and losses from derivatives not involved in a fair value hedging relationship or in a hedging relationship recognized in the Partnership’s consolidated statements of operations for the three and six months ended June 30, 2014 and 2013 (in thousands):

		Amount of Gain (Loss)					Amount of Gain (Loss)
	Location of	Recognized in Income					Recognized in Income
	Gain (Loss)	on Derivatives					on Derivatives
	Recognized in	Three Months Ended					Six Months Ended
Derivatives Not Designated as	Income on	June 30,			June 30,		June 30,			June 30,
Hedging Instruments	Derivatives	2014			2013		2014			2013

Product contracts	Cost of sales	$	(12,055	)	$	2,981	$	3,488		$	3,647
Foreign currency contracts	Cost of sales	(97		)	555		(154		)	234
Total		$	(12,152	)	$	3,536	$	3,334		$	3,881

The interest rate cap agreement was de-designated as a cash flow hedge in June 2014. The amount of gain (loss) recognized in income was immaterial for the three and six months ended June 30, 2014.

Credit Risk

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

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

Note 6. Debt

Credit Agreement

On December 16, 2013, the Partnership entered into a Second Amended and Restated Credit Agreement (the “Credit Agreement”), which increased the total commitments available under the Credit Agreement to $1.625 billion from $1.615 billion under the prior credit agreement. The Credit Agreement will mature on April 30, 2018.

As of June 30, 2014, there were two facilities under the Credit Agreement:

• a working capital revolving credit facility to be used for working capital purposes and letters of credit in the principal amount equal to the lesser of the Partnership’s borrowing base and $1.0 billion; and

• a $625.0 million revolving credit facility to be used for acquisitions, joint ventures, capital expenditures, letters of credit and general corporate purposes.

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Note 6. Debt (continued)

In addition, the Credit Agreement has an accordion feature whereby the Partnership may request on the same terms and conditions of its then existing credit agreement, provided no Event of Default (as defined in the Credit Agreement) then exists, an increase to the working capital revolving credit facility, the revolving credit facility, or both, by up to another $300.0 million, in the aggregate, for a total credit facility of up to $1.925 billion. Any such request for an increase by the Partnership must be in a minimum amount of $25.0 million. The Partnership cannot provide assurance, however, that its lending group will agree to fund any request by the Partnership for additional amounts in excess of the total available commitments of $1.625 billion.

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

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

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

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

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(Unaudited)

Note 6. Debt (continued)

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

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

The average interest rates for the Credit Agreement were 3.5% and 4.5% for the three months ended June 30, 2014 and 2013, respectively, and 3.6% and 4.3% for the six months ended June 30, 2014 and 2013, respectively.

As of June 30, 2014, 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.

The Credit Agreement provides for a letter of credit fee equal to the then applicable working capital rate or then applicable revolver rate (each such rate as defined in the Credit Agreement) per annum for each letter of credit issued. In addition, the Partnership incurs a commitment fee on the unused portion of each facility under the Credit Agreement, ranging from 0.375% to 0.50% per annum.

The Partnership classifies a portion of its working capital revolving credit facility as a long-term liability because the Partnership has a multi-year, long-term commitment from its bank group. The long-term portion of the working capital revolving credit facility was $132.0 million and $327.0 million at June 30, 2014 and December 31, 2013, respectively, representing the amounts expected to be outstanding during the entire year. In addition, the Partnership classifies a portion of its working capital revolving credit facility as a current liability because it repays amounts outstanding and reborrows funds based on its working capital requirements. At June 30, 2014 and December 31, 2013, the current portion of the working capital revolving credit facility was $175.0 million and $0, respectively, representing the amount the Partnership expects to pay down during the course of the year. Due to unexpected excess cash received during the six months ended June 30, 2014, the Partnership paid down a portion of the working capital revolving credit facility that was previously classified as long term at December 31, 2013.

As of June 30, 2014, the Partnership had total borrowings outstanding under the Credit Agreement of $579.6 million, including $272.6 million outstanding on the revolving credit facility. In addition, the Partnership had outstanding letters of credit of $170.8 million. Subject to borrowing base limitations, the total remaining availability for borrowings and letters of credit was $874.6 million and $479.9 million at June 30, 2014 and December 31, 2013, respectively.

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

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(Unaudited)

Note 6. Debt (continued)

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 June 30, 2014. The Credit Agreement also contains a representation whereby there can be no event or circumstance, either individually or in the aggregate, that has had or could reasonably be expected to have a Material Adverse Effect (as defined in the Credit Agreement). In addition, the Credit Agreement limits distributions by the Partnership to its unitholders to the amount of Available Cash (as defined in the Partnership’s partnership agreement).

8.0% Senior Notes

On February 14, 2013, the Partnership entered into a note purchase agreement with FS Energy and Power Fund (“FS Energy”), with respect to the issue and sale by the Partnership to FS Energy of an aggregate principal amount of $70.0 million unsecured 8.0% Senior Notes due 2018 (the “8.0% Notes”). The 8.0% Notes were issued in a private placement exempt from registration under the Securities Act of 1933, as amended (the “Securities Act”) and were not registered under the Securities Act or any state securities laws. Interest on the 8.0% Notes accrued from February 14, 2013 and was paid semi-annually on February 14 and August 14 of each year, beginning on August 14, 2013.

Closing of the offering occurred on February 14, 2013. The 8.0% Notes were sold to FS Energy at 97% of their face amount, resulting in net proceeds to the Partnership of approximately $67.9 million. Additionally, the Partnership separately paid fees and offering expenses. The discount of $2.1 million at issuance was accreted as additional interest. On February 15, 2013, the Partnership used the net proceeds from the offering, after paying fees and offering expenses, to finance a portion of its acquisition of all of the outstanding membership interests in Cascade Kelly and to pay related transaction costs.

7.75% Senior Notes

On December 23, 2013, the Partnership entered into a note purchase agreement with FS Energy and Power Fund, KARBO, L.P., Kayne Anderson Capital Income Partners (QP), L.P., Kayne Anderson Income Partners, L.P., Kayne Anderson Infrastructure Income Fund, L.P., Kayne Anderson Non-Traditional Investments, L.P., KANTI (QP), L.P. and Kayne Energy Credit Opportunities, L.P. as purchasers (the “Purchasers”), with respect to the issue and sale by the Partnership to the Purchasers of an aggregate principal amount of $80.0 million unsecured 7.75% Senior Notes due 2018 (the “7.75% Notes”). The 7.75% Notes were issued in a private placement exempt from registration under the Securities Act and were not registered under the Securities Act or any state securities laws. Interest was paid on the 7.75% Notes semi-annually on December 23 and June 23 of each year, beginning on June 23, 2014.

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

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(Unaudited)

Note 6. Debt (continued)

Exchange Rights Agreements

On June 19, 2014, the Partnership and GLP Finance (the “Issuers”) entered into a letter agreement (the “Exchange Rights Agreements”) with each of FS Energy and certain funds managed by Kayne Anderson Capital Advisors, L.P. pursuant to which the parties agreed to modifications to or waivers of certain of the provisions of the indentures governing the 8.0% Senior Notes and the 7.75% Senior Notes (collectively, the “Existing HY Notes”) for purposes of effecting the repayment of the Existing HY Notes with a portion of the proceeds of the Issuers’ private placement of the 6.25% Notes (defined below) and the subsequent issuance of a portion of the 6.25% Notes to the holders of the Existing HY Notes.

6.25% Senior Notes

On June 19, 2014, 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. 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. The Partnership used the net proceeds from the offering to repay a portion of the borrowings outstanding under its revolving credit facility and to repurchase or exchange all of its $150.0 million of the Existing HY Notes in accordance with the Exchange Rights Agreements, as follows: the principal amount of $70.0 million of the 8.0% Senior Notes and the principal amount of $80.0 million of the 7.75% Senior Notes, including premium payments but excluding accrued and unpaid interest. Specifically, the Partnership paid $40.2 million to the holders of the Existing HY Notes and exchanged the remaining $110.0 million of the Existing HY Notes for $116.0 million of the 6.25% Notes. The additional $6.0 million provided to the holders of the Existing HY Notes as a make-whole provision was treated as a discount to the 6.25% Notes included in senior notes in the accompanying balance sheet at June 30, 2014.

The Partnership accounted for the exchange of $110.0 million of the Existing HY Notes to the 6.25% Notes as a modification of debt rather than an extinguishment of debt in accordance with ASC 70-50, “Modification and Extinguishments,” as the cash flow effect on a present value basis was less than 10% which is not deemed a substantial modification of terms. As a result of the $40.0 million extinguishment of the remaining principal debt, the Partnership incurred expenses of $1.6 million associated with the write-off of a portion of the original issue discount and deferred financing fees. These expenses are included in interest expense in the accompanying statements of operations for the three and six months ended June 30, 2014.

Additionally, as a result of the modification, the pro rata portion of the unamortized original issue discount and deferred financing fees associated with the Existing HY Notes remaining will be amortized over the term of the 6.25% Notes.

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(Unaudited)

Note 6. Debt (continued)

Indenture

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

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

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

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

Registration Rights Agreement

On June 24, 2014, the Issuers and the subsidiary guarantors entered into a registration rights agreement (the “Registration Rights Agreement”) with the Initial Purchasers in connection with the Issuers’ private placement of the 6.25% Notes. Under the Registration Rights Agreement, the Issuers and the subsidiary guarantors have 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 will not be 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. Under specified circumstances, the Issuers and the subsidiary guarantors have also agreed to use commercially reasonable efforts to cause to become effective a shelf registration statement relating to resales of the 6.25% Notes. If the exchange offer is not completed on or before the 360th day after June 24, 2014, the annual interest rate borne by the 6.25% Notes will be increased by 1.0% per annum until the exchange offer is completed or the shelf registration statement is declared effective (or automatically becomes effective).

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Note 6. Debt (continued)

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, 2014 and had an outstanding balance of $3.7 million at June 30, 2014 and December 31, 2013. 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 capitalized additional financing fees of $5.8 million for the three and six months ended June 30, 2014 associated with the issuance of the Partnership’s $375.0 million aggregate principal amount of its 6.25% senior notes due 2022. Amortization expenses of approximately $1.3 million and $1.7 million for the three months ended June 30, 2014 and 2013, respectively, and $2.6 million and $3.3 million for the six months ended June 30, 2014 and 2013, respectively, are included in interest expense in the accompanying consolidated statements of operations. Unamortized fees are included in other current assets and other long-term assets.

Note 7. Related Party Transactions

The Partnership is a party to a Second Amended and Restated Terminal Storage Rental and Throughput Agreement, as amended, with Global Petroleum Corp. (“GPC”), an affiliate of the Partnership that is 100% owned by members of the Slifka family. The agreement, which extends through July 31, 2015 with annual renewal options thereafter, is accounted for as an operating lease. After July 31, 2015, the agreement continues for successive one year terms unless either party gives notice to terminate at least 90 days prior to the expiration of the then current term. The expenses under this agreement totaled approximately $2.3 million and $2.2 million for the three months ended June 30, 2014 and 2013, respectively, and $4.6 million and $4.5 million for the six months ended June 30, 2014 and 2013, respectively.

Pursuant to an Amended and Restated Services Agreement with GPC, GPC provides certain terminal operating management services to the Partnership and uses certain administrative, accounting and information processing services of the Partnership. The expenses from these services totaled approximately $24,000 for each of the three months ended June 30, 2014 and 2013 and $48,000 for each of the six months ended June 30, 2014 and 2013. These charges were recorded in selling, general and administrative expenses in the accompanying consolidated statements of operations. On March 9, 2012, in connection with the Partnership’s acquisition of Alliance, the agreement was amended to include the services provided by GPC to Alliance. The agreement is for an indefinite term, and either party may terminate its receipt of some or all of the services thereunder upon 180 days’ notice at any time. As of June 30, 2014, no such notice of termination was given by either party.

In addition, on March 9, 2012, following the closing of the acquisition of Alliance, Global Companies and AE Holdings LLC (“AE Holdings”) entered into a shared services agreement pursuant to which Global Companies provides AE Holdings with certain tax, accounting, treasury and legal support services for which AE Holdings pays Global Companies $15,000 per year. The shared services agreement is for an indefinite term and AE Holdings may terminate its receipt of some or all of the services upon 180 days’ notice. As of June 30, 2014, no such notice of termination was given by AE Holdings.

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(Unaudited)

Note 7. Related Party Transactions (continued)

The General Partner employs all of the Partnership’s employees, except for its gasoline station and convenience store employees and certain union personnel, who are employed by GMG. The Partnership reimburses the General Partner for expenses incurred in connection with these employees. These expenses, including payroll, payroll taxes and bonus accruals, were $14.2 million and $17.3 million for the three months ended June 30, 2014 and 2013, respectively, and $36.3 million and $31.1 million for the six months ended June 30, 2014 and 2013, respectively. The Partnership also reimburses the General Partner for its contributions under the General Partner’s 401(k) Savings and Profit Sharing Plan 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):

	June 30,		December 31,
	2014		2013
Receivables from GPC	$	4	$	436
Receivables from the General Partner (1)	1,935		968
Total	$	1,939	$	1,404

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

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: 99.17% to the common unitholders, pro rata, and 0.83% to the General Partner, until the Partnership distributes for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter; and thereafter, cash in excess of the minimum quarterly distribution is distributed to the unitholders and the General Partner based on the percentages as provided below.

As holder of the IDRs, the General Partner is entitled to incentive distributions if the amount that the Partnership distributes with respect to any quarter exceeds specified target levels shown below:

	Total Quarterly Distribution	Marginal Percentage Interest in Distributions
	Target Amount	Unitholders		General Partner
Minimum Quarterly Distribution	$0.4625	99.17	%	0.83	%
First Target Distribution	$0.4625	99.17	%	0.83	%
Second Target Distribution	above $0.4625 up to $0.5375	86.17	%	13.83	%
Third Target Distribution	above $0.5375 up to $0.6625	76.17	%	23.83	%
Thereafter	above $0.6625	51.17	%	48.83	%

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(Unaudited)

Note 8. Cash Distributions (continued)

The Partnership paid the following cash distributions during 2014 (in thousands, except per unit data):

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

02/14/14 (1)	$	0.6125	$	16,802	$	140	$	932	$	17,874
05/15/14 (2)	0.6250		17,145		143		1,035		18,323

(1) This distribution of $0.6125 per unit resulted in the Partnership exceeding its second target level distribution for the fourth quarter of 2013. As a result, the General Partner, as the holder of the IDRs, received an incentive distribution.

(2) This distribution of $0.6250 per unit resulted in the Partnership exceeding its second target level distribution for the first quarter of 2014. As a result, the General Partner, as the holder of the IDRs, received an incentive distribution.

In addition, on July 23, 2014, the board of directors of the General Partner declared a quarterly cash distribution of $0.6375 per unit ($2.55 per unit on an annualized basis) for the period from April 1, 2014 through June 30, 2014. On August 14, 2014, the Partnership will pay this cash distribution to its common unitholders of record as of the close of business August 5, 2014. This distribution will result in the Partnership exceeding its second target level distribution for the quarter ended June 30, 2014.

Note 9. Segment Reporting

The Partnership engages in the distribution of refined petroleum products, renewable fuels, crude oil, natural gas and propane. The Partnership also engages in the purchasing, selling and logistics of transporting domestic and Canadian crude oil and other products. The Partnership’s operating segments are based upon the revenue sources for which discrete financial information is reviewed by the chief operating decision maker (the “CODM”) and include Wholesale, Gasoline Distribution and Station Operations (“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 and six months ended June 30, 2014 and 2013, the Commercial operating segment did not meet the quantitative metrics for disclosure as a reportable segment on a stand-alone basis as defined in accounting guidance related to segment reporting. However, the Partnership has elected to present segment disclosures for the Commercial operating segment as management believes such disclosures are meaningful to the user of the Partnership’s financial information. The accounting policies of the segments are the same as those described in Note 2, “Summary of Significant Accounting Policies,” in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2013.

In the Wholesale reporting segment, the Partnership sells unbranded gasoline (including gasoline blendstocks such as ethanol and naphtha) and diesel to unbranded gasoline customers and other resellers of transportation fuels. The Partnership sells home heating oil, diesel, kerosene, residual oil and propane to home heating oil and propane retailers and wholesale distributors. The Partnership also sells and transports crude oil to refiners. Generally, customers use their own vehicles or contract carriers to take delivery of the gasoline and distillate products at bulk terminals and inland storage facilities that the Partnership owns or controls or with which it has throughput or exchange arrangements. Crude oil is aggregated by truck or pipeline in the mid-continent, transported on land by train and shipped to refineries on the East Coast and West Coast in barges. Additionally, ethanol is shipped primarily by rail and by barge. The results of Basin Transload and Cascade Kelly, both acquired in February 2013 (see Note 2), are included in the Wholesale segment.

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(Unaudited)

Note 9. Segment Reporting (continued)

In the GDSO reporting segment, the Partnership sells branded and unbranded gasoline to gasoline stations and other sub-jobbers. This segment also includes gasoline, convenience store, car wash and other ancillary sales at the Partnership’s directly operated stores, as well as rental income from dealer leased or commission agent leased gasoline stations.

The Commercial segment includes sales and deliveries to end user customers in the public sector and to large commercial and industrial end users of unbranded gasoline, home heating oil, diesel, kerosene, residual oil, renewable fuels and natural gas. In the case of commercial and industrial end user customers, the Partnership sells products primarily either through a competitive bidding process or through contracts of various terms. The Commercial segment also includes sales of custom blended fuels delivered by barges or from a terminal dock to ships through bunkering activity.

Commercial segment end user customers include federal and state agencies, municipalities, large industrial companies, many autonomous authorities such as transportation authorities and water resource authorities, colleges and universities and a group of small utilities. In the Commercial segment, the Partnership generally arranges the delivery of the product to the customer’s designated location. The Partnership typically hires third-party common carriers to deliver the product.

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

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(Unaudited)

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						Six Months Ended
	June 30,						June 30,
	2014			2013			2014			2013
Wholesale Segment (1):
Sales
Gasoline and gasoline blendstocks	$	2,153,729		$	1,959,686		$	4,148,285		$	4,161,155
Crude oil (2)	643,040			1,053,389			1,234,269			2,037,354
Other oils and related products (3)	588,280			655,933			2,001,051			1,988,487
Total	$	3,385,049		$	3,669,008		$	7,383,605		$	8,186,996
Product margin
Gasoline and gasoline blendstocks	$	(4,074	)	$	12,358		$	45,589		$	(17,068	)
Crude oil (2)	30,096			19,714			53,586			45,882
Other oils and related products (3)	8,527			10,013			43,143			27,671
Total (4)	$	34,549		$	42,085		$	142,318		$	56,485
Gasoline Distribution and Station Operations Segment:
Sales
Gasoline	$	892,202		$	833,121		$	1,661,106		$	1,578,711
Station operations (5)	43,192			37,313			77,164			68,921
Total	$	935,394		$	870,434		$	1,738,270		$	1,647,632
Product margin
Gasoline	$	39,043		$	38,897		$	72,323		$	67,090
Station operations (5)	23,570			19,939			42,704			37,775
Total	$	62,613		$	58,836		$	115,027		$	104,865
Commercial Segment:
Sales	$	249,177		$	232,314		$	564,673		$	526,318
Product margin	$	5,732		$	6,170		$	18,061		$	16,595
Combined sales and product margin:
Sales	$	4,569,620		$	4,771,756		$	9,686,548		$	10,360,946
Product margin (4)(6)	$	102,894		$	107,091		$	275,406		$	177,945
Depreciation allocated to cost of sales	(15,606		)	(13,294		)	(29,757		)	(25,076		)
Combined gross profit (4)	$	87,288		$	93,797		$	245,649		$	152,869

(1) Segment reporting results for the prior period have been reclassified to conform to the Partnership’s current presentation.

(2) Crude oil consists of the Partnership’s crude oil sales and revenue from its logistics activities and includes the February 2013 acquisitions of Basin Transload and Cascade Kelly. As the Basin Transload and Cascade Kelly assets were not in place for a portion of the six months ended June 30, 2013, the above results are not directly comparable for periods prior to February 2013.

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

(4) For the three months ended June 30, 2014 and 2013, amounts include decreases of $43,400 and $10.6 million, respectively, in the mark to market loss related to RIN forward commitments, and a $3.1 million decrease and a $6.5 million increase, respectively, in the mark to market value of the renewable volume obligation (“RVO”). For the six months ended June 30, 2014 and 2013, amounts include a $6.1 million decrease and a $22.1 million increase, respectively, in the mark to market loss related to RIN forward commitments and a $12.3 million decrease and a $9.1 million increase, respectively, in the mark to market value of the RVO deficiency.

(5) Station operations primarily consist of convenience store sales at the Partnership’s directly operated stores and rental income from dealer leased or commission agent leased gasoline stations.

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

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(Unaudited)

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						Six Months Ended
	June 30,						June 30,
	2014			2013			2014			2013
Combined gross profit (1)	$	87,288		$	93,797		$	245,649		$	152,869
Operating costs and expenses not allocated to operating segments:
Selling, general and administrative expenses	31,673			25,680			68,971			51,343
Operating expenses	51,029			47,367			98,981			90,707
Amortization expense	4,524			4,774			9,052			8,548
Total operating costs and expenses	87,226			77,821			177,004			150,598
Operating income (1)	62			15,976			68,645			2,271
Interest expense	(12,246		)	(10,772		)	(23,353		)	(21,258		)
Income tax (expense) benefit	(94		)	—			(416		)	1,875
Net (loss) income (1)	(12,278		)	5,204			44,876			(17,112		)
Net income attributable to noncontrolling interest	(441		)	(379		)	(585		)	(130		)
Net (loss) income attributable to Global Partners LP (1)	$	(12,719	)	$	4,825		$	44,291		$	(17,242	)

(1) For the three months ended June 30, 2014 and 2013, amounts include decreases of $43,400 and $10.6 million, respectively, in the mark to market loss related to RIN forward commitments, and a $3.1 million decrease and a $6.5 million increase, respectively, in the mark to market value of the RVO. For the six months ended June 30, 2014 and 2013, amounts include a $6.1 million decrease and a $22.1 million increase, respectively, in the mark to market loss related to RIN forward commitments and a $12.3 million decrease and a $9.1 million increase, respectively, in the mark to market value of the RVO deficiency.

The Partnership’s foreign sales were immaterial for the three and six months ended June 30, 2014 and 2013. The Partnership has no foreign assets.

Segment Assets

In connection with its acquisitions of Cascade Kelly and a 60% membership interest in Basin Transload in February 2013, the Partnership acquired assets, including goodwill, of approximately $240.5 million, of which approximately $90.0 million of property and equipment has primarily been allocated to the Wholesale segment as of the respective acquisition dates. The Partnership acquired retail gasoline stations from Alliance in March 2012 and ExxonMobil in September 2010 which have been allocated to the GDSO 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 June 30, 2014 and December 31, 2013 (in thousands):

	Wholesale		Commercial		GDSO		Unallocated (1)		Total
June 30, 2014	$	81,119	$	—	$	499,124	$	1,627,639	$	2,207,882
December 31, 3013	$	83,208	$	—	$	499,966	$	1,844,748	$	2,427,922

(1) Includes 40% owned by the noncontrolling interest at Basin Transload.

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(Unaudited)

Note 10. Property and Equipment

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

	June 30,			December 31,
	2014			2013
Buildings and improvements	$	635,854		$	601,900
Land	289,466			287,044
Fixtures and equipment	23,488			19,890
Construction in process	55,449			59,277
Capitalized internal use software	5,847			5,847
Total property and equipment	1,010,104			973,958
Less accumulated depreciation	(198,796		)	(170,322		)
Total	$	811,308		$	803,636

At June 30, 2014, construction in process includes $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 by 2016; therefore, as of June 30, 2014, the fair value of the ethanol plant is included in construction in process. After the plant has been successfully placed into service, depreciation will commence.

The Partnership evaluates its assets for impairment on a quarterly basis. No impairments were required for the three and six months ended June 30, 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.

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

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

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

In connection with the September 2010 acquisition of retail gasoline stations from ExxonMobil, the Partnership assumed certain environmental liabilities, including ongoing environmental remediation at and monitoring activities at certain of the acquired sites and future remediation activities required by applicable federal, state or local law or regulation. Remedial action plans are in place with the applicable state regulatory agencies for the majority of these locations, including plans for soil and groundwater treatment systems at certain sites. Based on consultations with environmental engineers, the Partnership’s estimated cost of the remediation is expected to be approximately $30.0 million to be expended over an extended period of time. As a result, the Partnership recorded, on an undiscounted basis, total environmental liabilities of approximately $30.0 million.

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

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

In connection with the May 2007 acquisition of ExxonMobil’s Albany and Newburgh, New York and Burlington, Vermont terminals, the Partnership assumed certain environmental liabilities, including the remediation obligations under a proposed remedial action plan submitted by ExxonMobil to NYDEC with respect to the Albany, New York terminal. As a result, the Partnership recorded, on an undiscounted basis, total environmental liabilities of approximately $8.0 million.

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

The following table presents a summary roll forward of the Partnership’s environmental liabilities at June 30, 2014 (in thousands):

	Balance at											Balance at
	December 31,		Payments in			Dispositions			Other			June 30,
Environmental Liability Related to:	2013		2014			2014			Adjustments			2014
ExxonMobil Gasoline Stations	$	24,745	$	(237	)	$	(159	)	$	(305	)	$	24,044
Alliance Gasoline Stations	13,921		(176		)	—			14			13,759
Mutual Oil	625		—			—			—			625
Newburgh	1,500		—			—			—			1,500
Glenwood Landing and Inwood	301		(34		)	—			—			267
Albany	47		(3		)	—			—			44
Total environmental liabilities	$	41,139	$	(450	)	$	(159	)	$	(291	)	$	40,239

Current portion	$	3,377										$	3,340
Long-term portion	37,762											36,899
Total environmental liabilities	$	41,139										$	40,239

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. 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. At June 30, 2014 and December 31, 2013, the Partnership has approximately $2.1 million in total asset retirement obligations which are included in other long-term liabilities in the accompanying balance sheets.

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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 biofuel for the purpose of tracking its production, use, and trading as required by the Environmental Protection Agency’s (“EPA”) Renewable Fuel Standard that originated with the Energy Policy Act of 2005. To evidence that the required volume of renewable fuel is blended with gasoline, obligated parties must retire sufficient RINs to cover their 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. 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, the settlement of the RVO can occur, under certain deferral elections, 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 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 $0.7 million and $13.1 million at June 30, 2014 and December 31, 2013, respectively.

The Partnership may enter into RIN forward purchase and sales commitments. These contracts are valued at the end of each quarter based on the then RIN spot rate. The Partnership accrued for losses of these firm non-cancellable commitments of approximately $0.1 million and $6.2 million at June 30, 2014 and December 31, 2013, respectively.

Note 12. Long-Term Incentive Plan

The General Partner has a Long-Term Incentive Plan (“LTIP”) whereby 564,242 common units were initially authorized for issuance. On June 22, 2012, the Partnership’s common unitholders approved an amendment and restatement of the LTIP (the “Restated LTIP”). The Restated LTIP: (i) increases the number of common units available for delivery with respect to awards under the LTIP so that, effective June 22, 2012 a total of 4,300,000 common units are available for delivery with respect to awards under the Restated LTIP, (ii) adds a prohibition on repricing of unit options and unit appreciation rights without approval of the Partnership’s unitholders, except in the case of adjustments implemented to reflect certain Partnership transactions, (iii) adds a prohibition on granting unit options or unit appreciation rights with an exercise price less than the fair market value of a common unit on the grant date (other than “substitute awards” granted in substitution for similar awards held by individuals who become employees, consultants and directors of the Partnership or one of its affiliates as a result of a merger, consolidation or acquisition by the Partnership or its affiliate of another entity or the assets of another entity), (iv) permits the granting of fully-vested common units and (v) incorporates certain other non-material ministerial changes. Any units delivered pursuant to an award under the Restated LTIP may be acquired in the open market, issued by the Partnership, or any combination of the foregoing. The Restated LTIP provides for awards to employees, consultants and directors of the General Partner and employees and consultants of affiliates of the Partnership who perform services for the Partnership. The Restated LTIP allows for the award of options, unit appreciation rights, restricted units, phantom units, distribution equivalent rights, unit awards and substitute awards.

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Note 12. Long-Term Incentive Plan (continued)

Phantom Unit Awards

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

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

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

Compensation cost for an award of share-based employee compensation classified as equity, as is the case of the Partnership’s award, is recognized over the requisite service period. The requisite service period for the Partnership is from June 27, 2013, the grant date, through the vesting dates described above. The Partnership will recognize as compensation expense for the awards granted to employees and non-employee directors the value of the portion of the award that is ultimately expected to vest over the requisite service period on a straight-line basis. In accordance with the guidance issued for share-based compensation, the Partnership estimated forfeitures at the time of grant. Such estimates, which were based on the Partnership’s service history, will be revised, if necessary, in subsequent periods if actual forfeitures differ from estimates. The Partnership recorded compensation expense related to these awards of approximately $0.9 million and $1.7 million for the three and six months ended June 30, 2014, which is included in selling, general and administrative expenses in the accompanying consolidated statement of income. Compensation expense for the three and six months ended June 30, 2013 was immaterial. The total compensation cost related to the non-vested awards not yet recognized at June 30, 2014 was approximately $16.1 million and is expected to be recognized ratably over the remaining requisite service period.

Repurchase Program

In May 2009, the board of directors of the General Partner authorized the repurchase of the Partnership’s common units (the “Repurchase Program”) for the purpose of meeting the General Partner’s anticipated obligations to deliver common units under the LTIP and meeting the General Partner’s obligations under existing employment agreements and other employment related obligations of the General Partner (collectively, the “General Partner’s Obligations”). The General Partner is currently authorized to acquire up to 742,427 of its common units in the aggregate over an extended period of time, consistent with the General Partner’s Obligations. Common units of the Partnership may be repurchased from time to time in open market transactions, including block purchases, or in privately negotiated transactions. Such authorized unit repurchases may be modified, suspended or terminated at any time, and are subject to price, economic and market conditions, applicable legal requirements and available liquidity. Since the Repurchase Program was implemented, the General Partner repurchased 540,215 common units pursuant to the Repurchase Program for approximately $14.1 million, of which approximately $1.8 million was purchased in 2014.

Common units outstanding as reported in the accompanying consolidated financial statements at June 30, 2014 and December 31, 2013 excluded 214,616 and 169,816 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

Certain of the Partnership’s assets and liabilities are measured at fair value. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants at the measurement date.

The FASB established a fair value hierarchy, which prioritizes the inputs used in measuring fair value into the following three levels:

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

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

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

The following table presents those financial assets and financial liabilities measured at fair value on a recurring basis as of June 30, 2014 and December 31, 2013 (in thousands):

	Fair Value as of June 30, 2014												Fair Value as of December 31, 2013
	Total			Level 1			Level 2			Level 3			Total			Level 1			Level 2			Level 3
Assets:
Hedged inventories	$	241,333		$	—		$	241,333		$	—		$	452,302		$	—		$	452,302		$	—
Fair value of forward fixed price contracts	29,549			—			13,826			15,723			46,007			—			31,931			14,076
Swap agreements and options	338			13			325			—			116			74			42			—
Interest rate cap	—			—			—			—			25			—			25			—
Broker margin deposits	20,175			20,175			—			—			21,792			21,792			—			—
Pension plan	18,067			18,067			—			—			18,267			18,267			—			—
Total	$	309,462		$	38,255		$	255,484		$	15,723		$	538,509		$	40,133		$	484,300		$	14,076

Liabilities:
Obligations on forward fixed price contracts	$	(36,833	)	$	—		$	(17,978	)	$	(18,855	)	$	(38,197	)	$	—		$	(33,014	)	$	(5,183	)
Mark to market loss related to RIN forward commitments	(79		)	—			(79		)	—			(6,166		)	—			(6,166		)	—
Swap agreements and option contracts	(13		)	(13		)	—			—			(108		)	(74		)	(34		)	—
Foreign currency derivatives	(170		)	—			(170		)	—			(16		)	—			(16		)	—
Interest rate swaps	(8,751		)	—			(8,751		)	—			(9,462		)	—			(9,462		)	—
Total liabilities	$	(45,846	)	$	(13	)	$	(26,978	)	$	(18,855	)	$	(53,949	)	$	(74	)	$	(48,692	)	$	(5,183	)

This table excludes cash on hand and assets and liabilities that are measured at historical cost or any basis other than fair value. The carrying amounts of certain of the Partnership’s financial instruments, including cash equivalents, accounts receivable, accounts payable and other accrued liabilities approximate fair value due to their short maturities. The carrying value of the Partnership’s credit facilities approximate fair value due to the variable rate nature of these financial instruments. The fair values of the derivatives used by the Partnership are disclosed in Note 5.

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Note 13. Fair Value Measurements (continued)

The majority of the Partnership’s derivatives outstanding are reported at fair value based market quotes that are deemed to be observable inputs in an active market for similar assets and liabilities and are considered Level 2 inputs for purposes of fair value disclosures. Specifically, the fair values of the Partnership’s financial assets and financial liabilities provided above were derived from NYMEX and New York Harbor quotes for the Partnership’s hedged inventories, forward fixed price contracts, swap agreements and option contracts and from the LIBOR rates for the Partnership’s interest rate swaps and interest rate cap. The fair value of the foreign currency derivatives and the mark to market loss related to RIN forward commitments are based on broker price quotations. Except as discussed below, the Partnership has not changed its valuation techniques or Level 2 inputs during the three and six months ended June 30, 2014.

The fair value for the Partnership’s forward fixed price contracts related to crude oil are derived from a combination of quoted NYMEX market commodity prices as well as significant unobservable inputs (Level 3), including internally developed assumptions where there is little, if any, market activity. The unobservable inputs used in the measurement of the Partnership’s forward fixed price contracts include estimates for location basis, transportation and throughput costs net of an estimated margin for current market participants. Gains and losses recognized in earnings (or changes in net assets) are disclosed in Note 5.

The following table presents a summary of the changes in fair value of the Partnership’s Level 3 financial assets and liabilities at June 30, 2014:

Fair value at December 31, 2013	$	8,893
Change in fair value recorded in Cost of Sales	(12,025		)
Fair value at June 30, 2014	$	(3,132	)

The fair values of the Partnership’s pension plan assets at June 30, 2014 and December 31, 2013 were determined by Level 1 inputs which principally consist of quoted prices in active markets for identical assets. The plan assets primarily consisted of fixed income securities, equity securities and cash and cash equivalents.

For assets and liabilities measured on a non-recurring basis during the period, accounting guidance requires quantitative disclosures about the fair value measurements separately for each major category.

Financial Instruments

The fair value of the Partnership’s financial instruments approximated the carrying value as of June 30, 2014 and December 31, 2013, in each case due to the short-term nature and the variable interest rate of the financial instruments.

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 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.

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Note 14. Income Taxes (continued)

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

One of the Partnership’s wholly owned subsidiaries, GMG, is a taxable entity for federal and state income tax purposes. Current and deferred income taxes are recognized on the separate earnings of GMG. The after-tax earnings of GMG are included in the earnings of the Partnership. Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes for GMG. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. The Partnership calculates its current and deferred tax provision based on estimates and assumptions that could differ from actual results reflected in income tax returns filed in subsequent years. Adjustments based on filed returns are recorded when identified.

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.

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Note 15. Legal Proceedings (continued)

Other

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 SEC requesting information for relevant time periods primarily relating to the Partnership’s accounting for Renewable Identification Numbers and the recent restatement 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 cooperate fully with, and have begun producing 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 the Partnership’s subsidiary, Cascade Kelly, which covers both the production of ethanol and transshipping of crude oil by the Partnership’s bio-refinery in Clatskanie, Oregon (the “Existing Permit”). This Modification proposed to limit the number of trains carrying crude oil that the bio-refinery can receive as part of the Partnership’s transloading operations. The Partnership submitted a request for a hearing to contest the Modification, which allows the Existing Permit to remain in effect pending this appeal. The Administrative Law Judge set a hearing for September 30, 2014. The Partnership also received a Pre- Enforcement Notice (“PEN”) letter dated January 10, 2014 from ODEQ claiming that the Partnership is in violation of the Existing Permit and informing it that ODEQ is considering a possible notice of violation and penalty assessment. In summary, the PEN asserts that the Partnership may have received, and may be receiving, more crude oil than the Existing Permit allows. On March 27, 2014, ODEQ issued the Partnership a civil penalty assessment (“CPA”) of $117,292. The Partnership has meritorious defenses to the Modification, the PEN and the CPA and will vigorously contest any actions that may be taken by ODEQ with respect to the foregoing.

Separately, in August 2013, the Partnership submitted an application to ODEQ for a separate air emissions permit covering the transloading of crude oil by the bio-refinery (the “New Permit”). The Partnership is working through the customary permitting process with ODEQ. The draft of the New Permit is currently being finalized by ODEQ. The Partnership anticipates that the New Permit will be issued in the third quarter of 2014. The issuance of the New Permit will resolve ODEQ’s concerns regarding the Existing Permit as noted above. It is possible, however, that the issuance of the New Permit may be delayed and that a significant delay may have a negative impact on the Partnership’s operations in Oregon.

The Partnership received from the EPA, by letters dated November 2, 2011 and March 29, 2012, reporting requirements and testing orders (collectively, the “Requests for Information”) for information under the Clean Air Act. The Requests for Information are part of an EPA investigation to determine whether the Partnership has violated sections of the Clean Air Act at certain of its terminal locations in New England with respect to residual oil and asphalt. On June 6, 2014, a Notice of Violation 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 is engaged in discussions with the EPA with respect to the alleged violations. The Partnership does not believe that a material violation has occurred nor does the Partnership believe any adverse determination in connection with the Notice of Violation would have a material impact on its operations.

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Note 16. Changes in Accumulated Other Comprehensive Loss

The following table presents the changes in accumulated other comprehensive loss by component for the three and six months ended June 30, 2014 (in thousands):

Three Months Ended June 30, 2014	Pension Plan			Derivatives			Total
Balance at March 31, 2014	$	(1,063	)	$	(10,197	)	$	(11,260	)
Other comprehensive income before reclassifications of gain (loss)	598			212			810
Amount of gain (loss) reclassified from accumulated other comprehensive income	(255		)	—			(255		)
Total comprehensive income	343			212			555
Balance at June 30, 2014	$	(720	)	$	(9,985	)	$	(10,705	)

Six Months Ended June 30, 2014	Pension Plan			Derivatives			Total
Balance at December 31, 2013	$	(454	)	$	(10,856	)	$	(11,310	)
Other comprehensive income before reclassifications of gain (loss)	117			871			988
Amount of gain (loss) reclassified from accumulated other comprehensive income	(383		)	—			(383		)
Total comprehensive income	(266		)	871			605
Balance at June 30, 2014	$	(720	)	$	(9,985	)	$	(10,705	)

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 July 2013, the FASB issued Accounting Standards Update (“ASU”) No. 2013-11, “Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exist.” ASU 2013-11 amends the presentation requirements of ASC 740, “Income Taxes,” and requires an unrecognized tax benefit to be presented in the financial statements as a reduction to a deferred tax asset for a net operating loss carryforward, similar tax loss, or a tax credit carryforward. To the extent the tax benefit is not available at the reporting date under the governing tax law or if the entity does not intend to use the deferred tax asset for such purpose, the unrecognized tax benefit should be presented as a liability and not combined with deferred tax assets. The amendments are to be applied to all unrecognized tax benefits that exist as of the effective date and may be applied retrospectively to each prior reporting period presented. The Partnership adopted this guidance on January 1, 2014 which did not have a material impact on the Partnership’s financial position, results of operations or cash flows as the Partnership’s current practice is consistent with this standard.

Accounting Standards or Updates Not Yet Effective

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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(Unaudited)

Note 17. New Accounting Standards (continued)

In April 2014, the FASB issued 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 does not expect the adoption of this standard to have material impact on its consolidated financial statements, but will impact the reporting of any future dispositions.

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

Note 18. Subsequent Event

On July 23, 2014, the board of directors of the General Partner declared a quarterly cash distribution of $0.6375 per unit ($2.55 per unit on an annualized basis) for the period from April 1, 2014 through June 30, 2014. On August 14, 2014, the Partnership will pay this cash distribution to its common unitholders of record as of the close of business August 5, 2014.

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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, 2013, as well as any cautionary language in this report, describe the known material risks, uncertainties and events that may cause our actual results to differ materially from the expectations we describe in our forward-looking statements. Additional factors or events that may emerge from time to time, or those that we currently deem to be immaterial, could cause our actual results to differ, and it is not possible for us to predict all of them. You are cautioned not to place undue reliance on the forward-looking statements contained herein. The following factors are among those that may cause actual results to differ materially and adversely from our forward-looking statements:

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

· The condition of credit markets may adversely affect us.

· Our bank credit agreement and the 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 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, 2013 and Part II, Item 1A, “Risk Factors,” in this Quarterly Report on Form 10-Q.

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 applicable law. 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.

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Overview

General

We are a midstream logistics and marketing company that engages in the purchasing, selling and logistics of transporting domestic and Canadian crude oil and other products via rail, establishing a “virtual pipeline” from the mid-continent region of the United States and Canada to refiners and other customers on the East and West Coasts. We own and control transload terminals in North Dakota and Oregon that extend our origin-to-destination capabilities. We also own, control or have access to one of the largest terminal networks of refined petroleum products and renewable fuels in Massachusetts, Maine, Connecticut, Vermont, New Hampshire, Rhode Island, New York, New Jersey and Pennsylvania (collectively, the “Northeast”). We are one of the largest distributors of gasoline (including gasoline blendstocks such as ethanol and naphtha), distillates (such as home heating oil, diesel and kerosene), residual oil and renewable fuels to wholesalers, retailers and commercial customers in the New England states and New York. We are a major multi-brand gasoline distributor and, as of June 30, 2014, had a portfolio of approximately 900 owned, leased and/or supplied gasoline stations primarily in the Northeast. We receive revenue from retail sales of gasoline, convenience store sales and gasoline station rental income. We are also a distributor of natural gas and propane.

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

Collectively, we sold approximately $4.5 billion and $9.6 billion of refined petroleum products, renewable fuels, crude oil, natural gas and propane for the three and six months ended June 30, 2014, respectively. In addition, we had other revenues of approximately $43.2 million and $77.2 million for the three and six months ended June 30, 2014, respectively, primarily from convenience store sales at our directly operated stores and rental income from dealer leased or commission agent leased gasoline stations.

Like most independent marketers, we base our pricing on spot prices, fixed prices or indexed prices and routinely use the NYMEX, 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.

Wholesale

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

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

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

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Gasoline Distribution and Station Operations

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

In September 2010, we completed the acquisition from ExxonMobil Corporation of 190 retail gasoline stations, together with the rights to (i) supply Mobil-branded fuel to those stations as well as an additional 31 existing locations in Massachusetts, New Hampshire and Rhode Island, and (ii) expand supply opportunities for Mobil-branded and Exxon-branded fuel in certain other New England states. This acquisition expanded our wholesale supply business and added vertical integration to our transportation fuel business in New England. On March 1, 2012, we acquired Alliance Energy LLC (“Alliance”), a gasoline distributor and operator of gasoline stations and convenience stores. As of the date of the acquisition, Alliance’s portfolio included approximately 540 gasoline stations in the Northeast, of which it owned or held under long-term lease approximately 250 stations, and had supply contracts for the remaining stations. The Alliance acquisition expanded our geographic footprint for gasoline stations to include Connecticut, New Jersey, New York, Pennsylvania, Maine and Vermont. Alliance is a top-tier distributor of multiple brands, including Exxon, Mobil, Shell, Sunoco, CITGO and Gulf. Prior to the closing of the acquisition, Alliance was wholly owned by AE Holdings Corp. (“AE Holdings”) which, on March 1, 2012, was 95% owned by members of the Slifka family.

On April 26, 2012, we entered into an agreement with Getty Realty Corp. (“Getty Realty”) to supply and provide management services to more than 200 of its gasoline stations in New York and New Jersey. In November 2012, we signed a long-term lease agreement with Getty Realty which, as amended, enables us to supply gasoline to and operate gasoline stations for approximately 100 of those 200 sites, primarily in the New York City boroughs of Queens, Manhattan and the Bronx as well as in Long Island and Westchester County. As of December 31, 2013, the supply and management agreement with respect to the remaining sites expired in accordance with the terms of the agreement.

Commercial

This segment includes sales and deliveries to end user customers in the public sector and to large commercial and industrial end users of unbranded gasoline, home heating oil, diesel, kerosene, residual oil, renewable fuels and natural gas. In the case of commercial and industrial end user customers, we sell our products primarily either through a competitive bidding process or through contracts of various terms. Our Commercial segment also includes sales of custom blended distillates and residual oil delivered by barge or from a terminal dock to ships through bunkering activity. For the three and six months ended June 30, 2014 and 2013, the Commercial operating segment did not meet the quantitative metrics for disclosure as a reportable segment on a stand-alone basis. However, we have elected to present segment disclosures for the Commercial operating segment as we believe such disclosures are meaningful to the user of our financial information.

Products and Operational Structure

Our products primarily include gasoline, distillates, residual oil, renewable fuels, crude oil, natural gas and propane. We sell gasoline to branded and unbranded gasoline stations and other resellers of transportation fuels, as well as to customers in the public sector. The distillates we sell are used primarily for fuel for trucks and off-road construction equipment and for space heating of residential and commercial buildings. We receive crude oil in the mid-continent region of the United States and Canada and aggregate crude oil by truck or pipeline in the mid-continent, transport it on land by train and ship it to refiners on the East and West Coasts in barges. We sell residual oil to major housing units, such as public housing authorities, colleges and hospitals and large industrial facilities that use processed steam in their manufacturing processes. In addition, we sell bunker fuel, which we can custom blend, to cruise ships, bulk carriers and fishing fleets. We sell our natural gas to end users and our propane to home heating oil and propane retailers and wholesale distributors.

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

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first and fourth quarters of the calendar year. These factors may result in significant fluctuations in our quarterly operating results.

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

Outlook

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

· Our business is influenced by the overall forward market for refined petroleum products, renewable fuels and crude oil, and increases and/or decreases in the prices of these products may adversely impact our financial condition, results of operations and cash available for distribution to our unitholders and the amount of borrowing available for working capital under our credit agreement. Results from our purchasing, storing, terminalling, transporting and selling operations are influenced by prices for refined petroleum products, renewable fuels and crude oil, pricing volatility and the market for such products. Prices in the overall forward market for these products may affect our financial condition, results of operations and cash available for distribution to our unitholders. Our margins can be significantly impacted by the forward product pricing curve, often referred to as the futures market. We typically hedge our exposure to petroleum product and renewable fuel price moves with futures contracts and, to a lesser extent, swaps. In markets where futures prices are higher than current prices, referred to as contango, we may use our storage capacity to improve our margins by storing products we have purchased at lower prices in the current market for delivery to customers at higher prices in the future. In markets where futures prices are lower than current prices, referred to as backwardation, inventories can depreciate in value and hedging costs are more expensive. For this reason, in these backward markets, we attempt to reduce our inventories in order to minimize these effects. When prices for the products we sell rise, some of our customers may have insufficient credit to purchase supply from us at their historical purchase volumes, and their customers, in turn, may adopt conservation measures which reduce consumption, thereby reducing demand for product. Furthermore, when prices increase rapidly and dramatically, we may be unable to promptly pass our additional costs on to our customers, resulting in lower margins for us which could adversely affect our results of operations. Higher prices for the products we sell may (1) diminish our access to trade credit support and/or cause it to become more expensive and (2) decrease the amount of borrowings available for working capital under our credit agreement as a result of total available commitments, borrowing base limitations and advance rates thereunder. When prices for the products we sell decline, our exposure to risk of 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.

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· 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, or a work stoppage at railroads could also disrupt rail service. These events could result in service disruptions and increased cost which could also adversely affect our financial condition, results of operations and cash available for distribution to our unitholders. Other disruptions, such as those due to an act of terrorism or war, could also adversely affect our business.

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

· Our heating oil and residual oil financial results are seasonal and generally lower in the second and third quarters of the calendar year. Demand for some refined petroleum products, specifically home heating oil and residual oil for space heating purposes, is generally higher during November through March than during April through October. We obtain a significant portion of these sales during the winter months. Therefore, our results of operations in heating oil and residual oil for the first and fourth calendar quarters are generally better than for the second and third quarters.

· Warmer weather conditions could adversely affect our results of operations and financial condition. Weather conditions generally have an impact on the demand for both home heating oil and residual oil. Because we supply distributors whose customers depend on home heating oil and residual oil for space heating purposes during the winter, warmer-than-normal temperatures during the first and fourth calendar quarters in the Northeast can decrease the total volume we sell and the gross profit realized on those sales.

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

· Changes in government usage mandates and tax credits could adversely affect the availability and pricing of ethanol, which could negatively impact our gasoline sales. Future demand for ethanol will be largely dependent upon the economic incentives to blend based upon the relative value of gasoline and ethanol, taking into consideration the EPA’s regulations on the 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

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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. However, there can be no assurances as to the timing and type of such changes in existing laws or the promulgation of new laws or the amount of any required expenditures associated therewith.

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

Gross Profit

We define gross profit as our sales minus product costs and terminal and gasoline station related depreciation expense allocated to cost of sales.

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;

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· 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.

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.

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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.

Three and Six Months Ended June 30, 2014 and 2013

During the three and six months ended June 30, 2014 and 2013, we experienced the following:

· Severe winter weather had both a positive and negative impact on our performance during the first quarter ended March 31, 2014. In our crude oil-by-rail business, extreme cold and snow impacted rail traffic, increasing congestion and causing delays which reduced crude oil activity. Some of the rail congestion, which negatively impacted crude oil activity, continued early into the second quarter ended June 30, 2014.

· Those same severe weather conditions and resulting rail congestion contributed to very favorable market conditions for us in gasoline blendstocks during the first quarter of 2014 as the availability of railcars for gasoline blendstocks was constrained and certain areas experienced shortages in that product. For the second quarter of 2014, however, our product margin from wholesale gasoline and gasoline blendstocks sales was negatively impacted by a challenging futures market, mainly a backward forward product pricing curve in gasoline blendstocks, primarily ethanol.

· Temperatures for the first quarter ended March 31, 2014 were 9% colder than normal and 11% colder than the same period in 2013 which improved our product margins for other oils and related products in our Wholesale segment and for weather sensitive products in our Commercial segment. Temperatures for the second quarter ended June 30, 2014 were 6% warmer than normal and 2% colder than last year which did not have a material impact on our weather related products. Temperatures for the six months ended June 30, 2014 were 6% colder than normal and 10% colder than the same period in 2013 which improved our product margins for other oils and related products in our Wholesale segment and for weather sensitive products in our Commercial segment for the first half of 2014.

· Our SG&A expenses increased for the three and six months ended June 30, 2014 compared to the same periods in 2013 as a result of increased overhead expenses and professional and consulting fees incurred to support our growing business as well as growth initiatives including our crude oil activities, retail gasoline stations and expansion opportunities. Operating expenses also increased for the three and six months ended June 30, 2014 compared to the same periods in 2013, primarily related to our retail gasoline stations, including expenses associated with our new retail locations and recently renovated sites.

· In our GDSO segment, rising gasoline prices typically compress our gasoline product margins and declining gasoline prices typically improve our gasoline product margins. The extent of the impact on our product margins depends on the magnitude, duration and direction of the market. Our GDSO gasoline product margins were negatively impacted during the three and six months ended June 30, 2014 and 2013 due to rising gasoline prices.

· In our GDSO segment, our station operations product margin was positively impacted for the three and six months ended June 30, 2014 by the completion of certain raze and rebuilds and to the addition of 11 C-Store/commission agent locations during 2014.

· Our product margin from wholesale gasoline and gasoline blendstocks were impacted by the changes in the RIN forward commitments and RVO deficiency for the three and six months ended June 30, 2014 and 2013 as follows:

Ø For the three months ended June 30, 2014, our product margin was favorably impacted due to the decreases of $43,400 in the mark to market loss related to RIN forward commitments and $3.1 million in the market to market value of the RVO deficiency, resulting in a $3.1 million favorable impact.

Ø For the three months ended June 30, 2013, our product margin was favorably impacted due to the decrease in the mark to market loss related to RIN forward commitments of $10.6 million, offset by an increase of $6.5 million in the mark to market value of the RVO deficiency, resulting in a $4.1 million favorable impact.

Ø For the six months ended June 30, 2014, our product margin was favorably impacted due to the decreases in the mark to market loss related to RIN forward commitments of $6.1 million and the mark to market value of the RVO deficiency of $12.3 million, resulting in an $18.4 million favorable impact which was

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largely offset by the expense incurred to purchase RINS during the first six months of 2014 to reduce these liabilities.

Ø For the six months ended June 30, 2013, our product margin was adversely impacted due to the increases in the mark to market loss related to RIN forward commitments of $22.1 million and the mark to market value of the RVO deficiency of $9.1 million, resulting in a $31.2 million unfavorable impact.

· Our product margins are affected by a variety of factors, including, but not limited to, changes in commodity prices, movement of products from foreign locales to and within the United States, changes in refiner demand, weekly and monthly refinery output levels, changes in local, domestic and worldwide inventory levels, seasonality, supply, weather and logistics disruptions.

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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):

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2014			2013			2014			2013
Net (loss) income attributable to Global Partners LP (1)	$	(12,719	)	$	4,825		$	44,291		$	(17,242	)
Net (loss) income per diluted limited partner unit (2)	$	(0.50	)	$	0.15		$	1.53		$	(0.68	)
EBITDA (1)(3)	$	19,136		$	32,563		$	105,630		$	34,079
Distributable cash flow (1)(4)	$	(4,164	)	$	18,986		$	65,356		$	8,307

Wholesale Segment (5):
Volume (gallons)	1,187,795			1,374,820			2,621,216			2,953,289
Sales
Gasoline and gasoline blendstocks	$	2,153,729		$	1,959,686		$	4,148,285		$	4,161,155
Crude oil (6)	643,040			1,053,389			1,234,269			2,037,354
Other oils and related products (7)	588,280			655,933			2,001,051			1,988,487
Total	$	3,385,049		$	3,669,008		$	7,383,605		$	8,186,996
Product margin
Gasoline and gasoline blendstocks	$	(4,074	)	$	12,358		$	45,589		$	(17,068	)
Crude oil (6)	30,096			19,714			53,586			45,882
Other oils and related products (7)	8,527			10,013			43,143			27,671
Total (1)	$	34,549		$	42,085		$	142,318		$	56,485
Gasoline Distribution and Station Operations Segment:
Volume (gallons)	262,150			264,190			498,817			507,501
Sales
Gasoline	$	892,202		$	833,121		$	1,661,106		$	1,578,711
Station operations (8)	43,192			37,313			77,164			68,921
Total	$	935,394		$	870,434		$	1,738,270		$	1,647,632
Product margin
Gasoline	$	39,043		$	38,897		$	72,323		$	67,090
Station operations (8)	23,570			19,939			42,704			37,775
Total	$	62,613		$	58,836		$	115,027		$	104,865
Commercial Segment:
Volume (gallons)	99,764			94,305			216,029			208,540
Sales	$	249,177		$	232,314		$	564,673		$	526,318
Product margin	$	5,732		$	6,170		$	18,061		$	16,595
Combined sales and Product margin:
Sales	$	4,569,620		$	4,771,756		$	9,686,548		$	10,360,946
Product margin (1)(9)	$	102,894		$	107,091		$	275,406		$	177,945
Depreciation allocated to cost of sales	(15,606		)	(13,294		)	(29,757		)	(25,076		)
Combined gross profit (1)	$	87,288		$	93,797		$	245,649		$	152,869

Weather conditions:
Normal heating degree days	784			784			3,654			3,654
Actual heating degree days	739			721			3,868			3,532
Variance from normal heating degree days	(6%		)	(8%		)	6%			(3%		)
Variance from prior period actual heating degree days	2%			18%			10%			21%

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

(3) 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.

(4) 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.

(5) Segment reporting results for the prior periods have been reclassified to conform to our current presentation.

(6) Crude oil consists of our crude oil sales and revenue from our logistics activities and includes the February 2013 acquisitions of Basin Transload and Cascade Kelly. As the Basin Transload and Cascade Kelly assets were not in place for a portion of the six months ended June 30, 2013, the above results are not directly comparable for periods prior to February 2013.

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

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

(9) Product margin is a non-GAAP financial measure 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.

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						Six Months Ended
	June 30,						June 30,
	2014			2013			2014			2013
Reconciliation of net (loss) income to EBITDA:
Net (loss) income	$	(12,278	)	$	5,204		$	44,876		$	(17,112	)
Net income attributable to noncontrolling interest	(441		)	(379		)	(585		)	(130		)
Net (loss) income attributable to Global Partners LP	(12,719		)	4,825			44,291			(17,242		)
Depreciation and amortization, excluding the impact of noncontrolling interest	19,530			16,966			37,602			31,938
Interest expense, excluding the impact of noncontrolling interest	12,231			10,772			23,321			21,258
Income tax expense (benefit)	94			—			416			(1,875		)
EBITDA	$	19,136		$	32,563		$	105,630		$	34,079

Reconciliation of net cash (used in) provided by operating activities to EBITDA:
Net cash (used in) provided by operating activities	$	(3,512	)	$	44,934		$	49,634		$	327,712
Net changes in operating assets and liabilities and certain non-cash items	12,703			(21,086		)	36,417			(310,091		)
Net cash from operating activities and changes in operating assets and liabilities attributable to noncontrolling interest	(2,380		)	(2,057		)	(4,158		)	(2,925		)
Interest expense, excluding the impact of noncontrolling interest	12,231			10,772			23,321			21,258
Income tax expense (benefit)	94			—			416			(1,875		)
EBITDA	$	19,136		$	32,563		$	105,630		$	34,079

For the three months ended June 30, 2014, EBITDA was favorably impacted due to the decreases of $43,400 in the mark to market loss related to RIN forward commitments and $3.1 million in the market to market value of the RVO deficiency, resulting in a $3.1 million favorable impact. For the three months ended June 30, 2013, EBITDA was favorably impacted due to the decrease in the mark to market loss related to RIN forward commitments of $10.6 million, offset by an increase of $6.5 million in the mark to market value of the RVO deficiency, resulting in a $4.1 million favorable impact. For the six months ended June 30, 2014, EBITDA was favorably impacted due to the decreases in the mark to market loss related to RIN forward commitments of $6.1 million and the mark to market value of the RVO deficiency of $12.3 million, resulting in an $18.4 million favorable impact which was largely offset by the expense incurred to purchase RINS during the first six months of 2014 to reduce these liabilities. For the six months ended June 30, 2013, EBITDA was adversely impacted due to the increases in the mark to market loss related to RIN forward commitments of $22.1 million and the mark to market value of the RVO deficiency of $9.1 million, resulting in a $31.2 million unfavorable impact.

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2014			2013			2014			2013
Reconciliation of net (loss) income to distributable cash flow:
Net (loss) income	$	(12,278	)	$	5,204		$	44,876		$	(17,112	)
Net income attributable to noncontrolling interest	(441		)	(379		)	(585		)	(130		)
Net (loss) income attributable to Global Partners LP	(12,719		)	4,825			44,291			(17,242		)
Depreciation and amortization, excluding the impact of noncontrolling interest	19,530			16,966			37,602			31,938
Amortization of deferred financing fees	1,284			1,747			2,567			3,318
Amortization of senior notes discount	105			105			210			158
Amortization of routine bank refinancing fees	(1,002		)	(985		)	(2,003		)	(1,970		)
Maintenance capital expenditures	(11,362		)	(3,672		)	(17,311		)	(7,895		)
Distributable cash flow	$	(4,164	)	$	18,986		$	65,356		$	8,307

Reconciliation of net cash (used in) provided by operating activities to distributable cash flow:
Net cash (used in) provided by operating activities	$	(3,512	)	$	44,934		$	49,634		$	327,712
Net changes in operating assets and liabilities and certain non-cash items	12,703			(21,086		)	36,417			(310,091		)
Amortization of deferred financing fees	1,284			1,747			2,567			3,318
Amortization of senior notes discount	105			105			210			158
Net cash from operating activities and changes in operating assets and liabilities attributable to noncontrolling interest	(2,380		)	(2,057		)	(4,158		)	(2,925		)
Amortization of routine bank refinancing fees	(1,002		)	(985		)	(2,003		)	(1,970		)
Maintenance capital expenditures	(11,362		)	(3,672		)	(17,311		)	(7,895		)
Distributable cash flow	$	(4,164	)	$	18,986		$	65,356		$	8,307

For the three months ended June 30, 2014, distributable cash flow was favorably impacted due to the decreases of $43,400 in the mark to market loss related to RIN forward commitments and $3.1 million in the market to market value of the RVO deficiency, resulting in a $3.1 million favorable impact. For the three months ended June 30, 2013, distributable cash flow was favorably impacted due to the decrease in the mark to market loss related to RIN forward commitments of $10.6 million, offset by an increase of $6.5 million in the mark to market value of the RVO deficiency, resulting in a $4.1 million favorable impact. For the six months ended June 30, 2014, distributable cash flow was favorably impacted due to the decreases in the mark to market loss related to RIN forward commitments of $6.1 million and the mark to market value of the RVO deficiency of $12.3 million, resulting in an $18.4 million favorable impact, which was largely offset by the expense incurred to purchase RINS during the first six months of 2014 to reduce these liabilities. For the six months ended June 30, 2013, distributable cash flow was adversely impacted due to the increases in the mark to market loss related to RIN forward commitments of $22.1 million and the mark to market value of the RVO deficiency of $9.1 million, resulting in a $31.2 million unfavorable impact.

Consolidated Results

Our total sales were $4.6 billion and $4.8 billion for the three months ended June 30, 2014 and 2013, respectively, a decrease of $0.2 billion, or 4%, primarily due to a decrease in volume sold. Our aggregate volumes of product sold were 1.5 billion gallons and 1.7 billion gallons for the three months ended June 30, 2014 and 2013, respectively. The 184 million gallon decrease in volume sold includes decreases of 187 million gallons in our Wholesale segment and 2 million in our GDSO segment, offset by an increase of 5 million gallons in our Commercial segment. The decrease in volume sold in our Wholesale segment was due primarily to a decrease in our crude oil activities as a result, in part, of lingering rail congestion and delays due to severe winter weather conditions and to a shift, primarily by one customer, from crude oil supply sales to fee-based crude oil delivery logistics. We also had a decrease in volume sold in distillates, offset by an increase in volume sold in gasoline and gasoline

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blendstocks. Our gross profit was $87.3 million and $93.8 million for the three months ended June 30, 2014 and 2013, respectively, a decrease of $6.5 million, or 7%, due primarily to a challenging futures market, mainly a backward forward product pricing curve in gasoline blendstocks, primarily ethanol. The decrease in our gross profit for the second quarter of 2014 was offset by increases in our crude oil activities and in our GDSO station operations product margin. Our GDSO gasoline distribution product margin improved but was negatively impacted by rising gasoline prices during the three months ended June 30, 2014 and 2013.

Our total sales were $9.7 billion and $10.4 billion for the six months ended June 30, 2014 and 2013, respectively, a decrease of $0.7 billion, or 7%, primarily due to a decrease in volume sold. Our aggregate volumes of product sold were 3.3 billion gallons and 3.7 billion gallons for the six months ended June 30, 2014 and 2013, respectively. The 333 million gallon decrease in volume sold includes decreases of 332 million gallons in our Wholesale segment and 8 million in our GDSO segment, offset by an increase of 7 million gallons in our Commercial segment. The decrease in volume sold in our Wholesale segment was due primarily to a decrease in our crude oil activity as a result, in part, of rail congestion and delays due to severe winter weather conditions in the first quarter and early into the second quarter of 2014 and to a shift, primarily by one customer, from crude oil supply sales to fee-based crude oil delivery logistics, offset by increases in volume sold in gasoline and gasoline blendstocks and in distillates due, in part, to colder weather period over period. The number of actual heating degree days increased by 10% to 3,868 for the first half of 2014 compared to 3,532 for the same period in 2013.

Our gross profit was $245.6 million and $152.9 million for the six months ended June 30, 2014 and 2013, respectively, an increase of $92.7 million, or 61%, which was attributed to (i) decreases of $6.1 million in the liability related to RIN forward commitments and $12.3 million in the mark to market value of the RVO deficiency during the first half of 2014, resulting in an $18.4 million favorable impact (which was largely offset by the expense incurred to purchase RINS during the first six months of 2014 to reduce these liabilities), compared to a $31.2 million negative impact during the first half of 2013 from increases of $22.1 million in the liability related to RIN forward commitments and $9.1 million in the mark to market value of the RVO deficiency, (ii) colder weather period over period which improved our product margins for other oils and related products in our Wholesale segment and for weather sensitive products in our Commercial segment, (iii) improved GDSO product margins which were, however, negatively impacted by rising gasoline prices during the six months ended June 30, 2014 and 2013, (iv) an increase in our crude oil activities and (v) severe winter weather, including extreme cold and snow and resulting rail congestion, which contributed to very favorable market conditions for us in gasoline blendstocks. Our gross profit for the first half of 2014 was negatively impacted by a challenging futures market during the second quarter of 2014, mainly a backward forward product pricing curve in gasoline blendstocks, primarily ethanol, and by extreme cold and snow which impacted rail traffic, increasing congestion and causing delays which reduced crude oil activities during the first quarter and early into the second quarter of 2014.

Wholesale Segment

Gasoline and Gasoline Blendstocks. Sales from wholesale gasoline and gasoline blendstocks were $2.2 billion and $2.0 billion for the three months ended June 30, 2014 and 2013, respectively. The increase of $0.2 billion was due to increases in volume sold and in gasoline prices. We had a negative product margin from wholesale gasoline and gasoline blendstocks sales of $4.1 million for the second quarter of 2014 compared to a product margin of $12.3 million for the same period in 2013, a decrease of $16.4 million. The decrease in product margin was due to a challenging futures market, mainly a backward forward product pricing curve in gasoline blendstocks, primarily ethanol.

Sales from wholesale gasoline and gasoline blendstocks were $4.1 billion and $4.2 billion for the six months ended June 30, 2014 and 2013, respectively. Our gasoline and gasoline blendstocks product margin increased by $62.7 million to $45.6 million for the six months ended June 30, 2014 compared to a negative product margin $17.1 million for the six months ended June 30, 2013. The increase was primarily due to an increase in gasoline blendstocks. During the first quarter of 2014, severe winter weather and resulting rail congestion contributed to very favorable market conditions for us in gasoline blendstocks as the availability of railcars for gasoline blendstocks was constrained and certain areas experienced shortages in that product. For the six months ended June 30, 2014, our gasoline and gasoline blendstocks product margin was favorably impacted by decreases of $6.1 million in the liability related to RIN forward commitments and $12.3 million in the mark to market value of the RVO deficiency, resulting in an $18.4 million favorable impact (which was largely offset by the expense incurred to purchase RINS during the first six months of 2014 to reduce these liabilities), compared to the six months ended June 30, 2013, when our gasoline and gasoline blendstocks product margin was negatively impacted by increases of $22.1 million in the liability related to RIN forward commitments and $9.1 million in the mark to market value of the RVO deficiency, resulting in a

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$31.2 million unfavorable impact. Despite the overall increase, our product margin for the first half of 2014 was negatively impacted by a challenging futures market during the second quarter, mainly a backward forward product pricing curve in gasoline blendstocks, primarily ethanol.

Crude Oil. Crude oil sales and logistics revenues were $0.6 billion and $1.0 billion for the three months ended June 30, 2014 and 2013, respectively, and $1.2 billion and $2.0 billion for the six months ended June 30, 2014 and 2013, respectively. The decreases of $0.4 billion, or 39%, and $0.8 billion, or 40%, for the three and six months ended June 30, 2014, respectively, were due to decreases in volume sold, primarily due to a shift, primarily by one customer, from crude oil supply sales to fee-based crude oil delivery logistics. Our product margin from crude oil was $30.1 million and $19.7 million for the three months ended June 30, 2014 and 2013, respectively, and $53.6 million and $45.9 million for the six months ended June 30, 2014 and 2013, respectively. Our crude oil product margin increased by $10.4 million, or 53%, and $7.7 million, or 17%, for the three and six months ended June 30, 2014, respectively, due to an increase in our crude oil activities but was negatively impacted due to extreme cold and snow during the first quarter and early into the second quarter of 2014 which impacted rail traffic, increasing congestion and causing delays which reduced crude oil activity.

Other Oils and Related Products. Sales from other oils and related products (primarily distillates, residual oil and propane) were $0.6 billion and $0.7 billion for the three months ended June 30, 2014 and 2013, respectively, and $2.0 billion for each of the six months ended June 30, 2014 and 2013. Our product margin from other oils and related products was $8.5 million and $10.0 million for the three months ended June 30, 2014 and 2013, respectively, a decrease of $1.5 million, or 15%, primarily in distillates. Our product margin from other oils and related products was $43.1 million and $27.7 million for the six months ended June 30, 2014 and 2013, respectively, an increase of $15.4 million, or 56%, due to improved margins in distillates and residual oil due to colder weather during the first six months of 2014 compared to the same period in 2013.

Gasoline Distribution and Station Operations Segment

Gasoline Distribution. Sales from gasoline distribution were $892.2 million and $833.1 million for the three months ended June 30, 2014 and 2013, respectively, and $1.7 billion and $1.6 billion for the six months ended June 30, 2014 and 2013, respectively. The increases of $59.1 million, or 7%, and $82.4 million, or 5%, for the three and six months ended June 30, 2014 were due primarily to an increase in gasoline prices. Our product margin from gasoline distribution was relatively flat at $39.0 million for the three months ended June 30, 2014 and 2013 and $72.3 million and $67.1 million for the six months ended June 30, 2014 and 2013, respectively, an increase of $5.2 million. Our product margins from gasoline distribution for the three and six months ended June 30, 2014 and 2013 were negatively impacted due to rising gasoline prices during the respective periods.

Station Operations. Our station operations, which consist primarily of convenience stores sales at our directly operated stores and rental income from dealer leased or commission agent leased gasoline stations, collectively generated revenues of approximately $43.2 million and $37.3 million for the three months ended June 30, 2014 and 2013, respectively, and $77.2 million and $68.9 million for the six months ended June 30, 2014 and 2014, respectively. Our product margin from station operations was $23.6 million and $19.9 million for the three months ended June 30, 2014 and 2013, respectively, and $42.7 million and $37.8 million for the six months ended June 30, 2014 and 2013, respectively. The increases in sales and product margin for the three and six months ended June 30, 2014 compared to the same period in 2013 were due to the completion of certain raze and rebuilds and to the addition of 11 C-Store/commission agent locations during 2014.

Commercial Segment

Our commercial sales were $249.2 million and $232.3 million for the three months ended June 30, 2014 and 2013, respectively, and $564.7 million and $526.3 million for the six months ended June 30, 2014 and 2013, respectively. Our commercial product margin was $5.7 million and $6.2 million for the three months ended June 30, 2014 and 2013, respectively, and $18.1 million and $16.6 million for the six months ended June 30, 2014 and 2013, respectively. In our Commercial segment, residual oil accounted for approximately 52% of our total commercial volume sold for each of the three months ended June 30, 2014 and 2013, and 48% and 49% of our total commercial volume sold for the six months ended June 30, 2014 and 2013, respectively. Distillates, gasoline and natural gas accounted for the remainder of the total commercial sales, volume sold and product margin.

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Selling, General and Administrative Expenses

SG&A expenses increased by $6.0 million, or 23%, to $31.6 million for the three months ended June 30, 2014 compared to $25.6 million for the same period in 2013. The increase includes increases of $1.8 million in overhead expenses, $1.7 million in professional fees, $1.3 million in incentive compensation, $0.8 million in depreciation expense and $1.6 million in other SG&A expenses, offset by decreases of $0.8 million in bank fees and $0.4 million in bad debt expense. The overall increase in SG&A expenses is attributed to additional costs to support our growing business as well as growth initiatives including our crude oil activities, retail gasoline stations and expansion opportunities.

SG&A expenses increased by $17.7 million, or 34%, to $69.0 million for the six months ended June 30, 2014 compared to $51.3 million for the same period in 2013. The increase, which reflects expenses for the full first six months of 2014 for Basin Transload and Cascade Kelly, includes increases of $9.8 million in incentive compensation, primarily accrued for in line with our performance, $4.4 million in professional fees, $3.6 million in overhead expenses, $1.3 million in depreciation expense and $2.4 million in other SG&A expenses, offset by decreases of $2.1 million in bad debt expense and $1.7 million in bank fees. The overall increase in SG&A expenses is attributed to additional costs to support our growing business as well as growth initiatives including our crude oil activities, retail gasoline stations and expansion opportunities.

Operating Expenses

Operating expenses increased by $3.7 million, or 8%, to $51.0 million for the three months ended June 30, 2014 compared to $47.4 million for the same period in 2013. The increase was primarily due to increases of $3.7 million in costs related to the operations of our retail gasoline stations, including, in part, additional rent, credit card and maintenance expenses associated with our new retail locations and recently renovated sites, and $0.9 million in operating costs associated with our terminals in Albany, New York. The increase in operating expenses was offset by decreases of $0.6 million in expenses at our East Providence, Rhode Island terminal as our lease expired in April 2013 and $0.3 million in other operating expenses.

Operating expenses increased by $8.3 million, or 9%, to $99.0 million for the six months ended June 30, 2014 compared to $90.7 million for the same period in 2013. The increase was primarily due to increases of $6.4 million in costs related to the operations of our retail gasoline stations, including, in part, additional rent, credit card and maintenance expenses associated with our new retail locations and recently renovated sites, $1.8 million in costs associated with our crude oil operations, including a full first six months of 2014 related to our 2013 acquisitions of Basin Transload and Cascade Kelly, $1.7 million in operating costs associated with our terminals in Albany, New York and $0.1 million in other operating expenses. The increase in operating expenses was offset by a $1.7 million decrease in expenses at our East Providence, Rhode Island terminal as our lease expired in April 2013.

Interest Expense

Interest expense was $12.2 million and $10.7 million for the three months ended June 30, 2014 and 2013, respectively, and $23.3 million and $21.2 million for the six months ended June 30, 2014 and 2013, respectively. The increases of $1.5 million and $2.1 million for the three and six months ended June 30, 2014, respectively, were primarily attributed to expenses of $1.6 million associated with the write-off of certain financing fees in connection with the issuance of the 6.25% Notes (see Note 6 to Notes to Consolidated Financial Statements). The increase in interest expense for the six months ended June 30, 2014 was also due to additional borrowings related to our 2013 acquisitions of Basin Transload and Cascade Kelly and interest expense related to our 8.0% senior notes and 7.75% senior notes.

Income Tax (Expense) Benefit

Income tax expense of $94,000 and $0 for the three months ended June 30, 2014 and 2013, respectively, and income tax expense of $0.4 million and income tax benefit of $1.9 million for the six months ended June 30, 2014 and 2013, respectively, reflect the operating results of our wholly owned subsidiary, Global Montello Group Corp., which is a taxable entity for federal and state income tax purposes.

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Net Income Attributable to Noncontrolling Interest

On February 1, 2013, we acquired a 60% membership interest in Basin Transload. The net income attributable to noncontrolling interest of approximately $0.4 million for each of the three months ended June 30, 2014 and 2013 and $0.6 million and $0.1 million for the six months ended June 30, 2014 and 2013, respectively, represents Basin Transload’s 40% ownership of the net (income) loss reported.

Liquidity and Capital Resources

Liquidity

Our primary liquidity needs are to fund our working capital requirements, capital expenditures and distributions and to service our indebtedness. Cash generated from operations and our working capital revolving credit facility provide our primary sources of liquidity. Working capital decreased by $131.4 million to $270.3 million at June 30, 2014 compared to $401.7 million at December 31, 2013, in part due to decreases in net accounts receivable and inventories of $140.7 million and $82.3 million, respectively, and an increase in the current portion of our working capital revolving credit facility of $175.0 million, partially offset by a decrease in accounts payable of $267.3 million. In addition, at June 30, 2014, working capital included an accrued liability for a mark to market value of the RVO deficiency of $0.7 million and a mark to market loss related to RIN forward commitments of $0.1 million. At December 31, 2013, working capital included an accrued liability for a mark to market value of the RVO deficiency of $13.1 million and a mark to market loss related to RIN forward commitments of $6.2 million.

On February 14, 2014, we paid a cash distribution to our common unitholders and our general partner of approximately $17.9 million for the fourth quarter of 2013. On May 15, 2014, we paid a cash distribution to our common unitholders and our general partner of approximately $18.3 million for the first quarter of 2014. On July 23, 2014, the board of directors of our general partner declared a quarterly cash distribution of $0.6375 per unit ($2.55 per unit on an annualized basis) for the period from April 1, 2014 through June 30, 2014 to our common unitholders of record as of the close of business August 5, 2014. We expect to pay the cash distribution of approximately $18.8 million on August 14, 2014.

Contractual Obligations

We have contractual obligations that are required to be settled in cash. The amounts of our contractual obligations at June 30, 2014 were as follows (in thousands):

	Payments due by period
	Total		Less than 1 year		1-3 years		4-5 years		More than 5 years
Revolver loan obligations (1)	$	618,810	$	8,100	$	319,305	$	291,405	$	—
Senior notes obligation (2)	562,500		11,719		46,875		46,875		457,031
Operating lease obligations (3)	524,793		50,278		190,475		129,249		154,791
Capital lease obligations	755		105		352		298		—
Other long-term liabilities (4)	119,837		5,292		21,405		29,662		63,478
Total	$	1,826,695	$	75,494	$	578,412	$	497,489	$	675,300

(1) Includes principal and interest on our working capital revolving credit facility and our revolving credit facility at June 30, 2014 and assumes a ratable payment through the expiration date. Our credit agreement has a contractual maturity of April 30, 2018 and no principal payments are required prior to that date. However, we repay amounts outstanding and reborrow funds based on our working capital requirements. Therefore, the current portion of the working capital revolving credit facility included in the accompanying balance sheets is the amount we expect to pay down during the course of the year, and the long-term portion of the working capital revolving credit facility is the amount we expect to be outstanding during the entire year.

(2) Includes principal and interest on our 6.25% senior notes due July 2022. No principal payments are required prior to maturity.

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

(4) Includes amounts related to our 15-year brand fee agreement entered into in 2010 with ExxonMobil, amounts related to our 5-year pipeline connection agreement entered into in March 2013 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 $17.3 million and $7.9 million in maintenance capital expenditures for the six months ended June 30, 2014 and 2013, 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, by example, rail capacity, dock capacity and tankage, diversifying product availability and storage flexibility at various terminals and adding terminals. We have the ability to fund our expansion capital expenditures through cash from operations or our credit agreement or by issuing debt securities or additional equity. We had approximately $26.9 million and $95.2 million in expansion capital expenditures for the six months ended June 30, 2014 and 2013, respectively, which are included in capital expenditures in the accompanying consolidated statements of cash flows. Specifically, for the six months ended June 30, 2014, expansion capital expenditures included approximately $10.0 million in new site development, rebuilds, expansion and improvements at certain retail gasoline stations, $8.7 million in costs associated with our crude oil activities, $3.8 million in costs associated with our propane storage and distribution facility in Albany, New York and $4.4 million in other expansion capital expenditures including, in part, office and computer upgrades at various terminals.

For the six months ended June 30, 2013, expansion capital expenditures included approximately $73.1 million in property and equipment associated with the acquisitions of Cascade Kelly and a 60% membership interest in Basin Transload. In addition, we had $22.1 million in expansion capital expenditures which consisted of $10.0 million in site expansion and improvements at certain retail gasoline stations, $6.2 million in costs associated with our crude oil activities, $3.7 million in costs associated with the building of a propane storage and distribution facility in Albany, New York, and $2.2 million in other expansion capital expenditures including, in part, construction costs at our compressed natural gas loading station in Bangor, Maine and terminal equipment at our Albany terminal. The $6.2 million in costs associated with our crude oil activities include, in part, tank construction projects, a pipeline connection at one of our transloading facilities for the storage and handling of crude oil, a build-out project to increase the rail receipt and throughput storage capacities of ethanol and crude oil and converting certain storage tanks for the handling of crude oil at our Albany, New York terminal and miscellaneous upgrades.

Certain of the $8.7 million and $6.2 million for the six months ended June 30, 2014 and 2013, respectively, in costs associated with our crude oil activities include expenditures related to our Beulah, North Dakota facility, 60% of which was funded by us and 40% was funded by the noncontrolling interest at Basin Transload. These costs are reported in the accompanying consolidated statement of cash flows as we concluded that we control the entity based on an evaluation of the outstanding voting interests (see Note 1 for additional information on the noncontrolling interest).

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):

	Six Months Ended
	June 30,
	2014			2013
Net cash provided by operating activities	$	49,634		$	327,712
Net cash used in investing activities	$	(40,855	)	$	(212,907	)
Net cash used in financing activities	$	(1,252	)	$	(11,109	)

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

Net cash provided by operating activities was $49.6 million and $327.7 million for the six months ended June 30, 2014 and 2013, respectively, for a period-over-period decrease in cash provided by operating activities of $278.1 million. The primary drivers of the decrease include the following (in thousands):

	Six Months Ended						Period over
	June 30,						Period
	2014			2013			Change
Decrease in accounts receivable	$	140,340		$	112,092		$	28,248
Decrease in inventories	$	82,285		$	294,735		$	(212,450	)
Decrease in accounts payable	$	(267,283	)	$	(158,837	)	$	(108,446	)
Decrease in the change in fair value of forward fixed price contracts	$	15,094		$	21,611		$	(6,517	)

For the six months ended June 30, 2014, the decreases in accounts receivable, inventories and accounts payable primarily reflect the change in activity as we continued to exit 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 a shift, primarily by one customer, from crude oil supply sales to fee-based crude oil delivery logistics.

Comparatively, for the six months ended June 30, 2013, the decreases in accounts receivable and accounts payable were primarily due to the decrease in our positive and negative exchange balances, offset by an increase in our crude oil activities. The decrease in inventories was due to carrying lower levels of inventory.

In addition, through the use of regulated exchanges or derivatives, we maintain a position that is substantially hedged with respect to our inventories. Specifically, due to market direction, the contracts supporting our forward fixed price hedge program provided less funds for the six months ended June 30, 2014 than for the same period in 2013.

Net cash used in investing activities was $40.8 million for the six months ended June 30, 2014 and included $26.9 million in expansion capital expenditures and $17.3 million in maintenance capital expenditures, offset by $3.4 million in proceeds from the sale of property and equipment.

For the six months ended June 30, 2013, net cash used in investing activities was $212.9 million and included $185.3 million related to our 2013 acquisitions ($91.1 million for our 60% membership interest in Basin Transload and $94.2 million for Cascade Kelly), $22.1 million in expansion capital expenditures and $7.9 million in maintenance capital expenditures, offset by $2.4 million in proceeds from the sale of property and equipment.

See “—Capital Expenditures” for a discussion of our expansion capital expenditures for the six months ended June 30, 2014 and 2013.

Net cash used in financing activities was $1.2 million for the six months ended June 30, 2014 and included $162.1 million in net payments on our revolving credit facility, $40.2 million in payments to the holders of the Existing HY Notes in connection with the issuance of the 6.25% Notes (see Note 6 of Notes to Consolidated Financial Statements), $36.0 million in cash distributions to our common unitholders and our general partner, $20.0 million in net payments on our working capital revolving credit facility, $4.2 million distributions to our noncontrolling interest and $1.8 million in the repurchase of common units pursuant to our repurchase program for future satisfaction of our general

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partner’s obligations. Net cash used in financing activities was offset by $258.9 million in proceeds from the issuance our 6.25% Notes and $4.2 million in capital contributions from our noncontrolling interest.

For the six months ended June 30, 2013, net cash used in financing activities was $111.1 million and included $213.0 million payments on our working capital revolving credit facility, $47.3 million in payments on our revolving credit facility, $33.0 million in cash distributions to our common unitholders and our general partner and $2.1 million in repurchased units withheld for tax obligations related to units distributed under an LTIP award granted in 2009, offset by $115.0 million in borrowings under our term loan, $67.9 million in proceeds from our 8.0% senior notes and $1.4 million in capital contributions from our noncontrolling interest.

Credit Agreement

On December 16, 2013, we entered into a second amended and restated credit agreement. Total commitments under our credit agreement are $1.625 billion. We repay amounts outstanding and reborrow funds based on our working capital requirements and, therefore, classify as a current liability the portion of the working capital revolving credit facility we expect to pay down during the course of the year. The long-term portion of the working capital revolving credit facility is the amount we expect to be outstanding during the entire year. The credit agreement will mature on April 30, 2018.

As of June 30, 2014, there were two facilities under the credit agreement:

• a working capital revolving credit facility to be used for working capital purposes and letters of credit in the principal amount equal to the lesser of our borrowing base and $1.0 billion; and

• a $625.0 million revolving credit facility to be used for acquisitions, joint ventures, capital expenditures, letters of credit and general corporate purposes.

In addition, the credit agreement has an accordion feature whereby we may request on the same terms and conditions of our then existing credit agreement, provided no Event of Default (as defined in the credit agreement) then exists, an increase to the working capital revolving credit facility, the revolving credit facility, or both, by up to another $300.0 million, in the aggregate, for a total credit facility of up to $1.925 billion. Any such request for an increase by us must be in a minimum amount of $25.0 million. We cannot provide assurance, however, that our lending group will agree to fund any request by us for additional amounts in excess of the total available commitments of $1.625 billion.

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

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

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

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

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

The average interest rates for the credit agreement were 3.5% and 4.5% for the three months ended June 30, 2014 and 2013, respectively, and 3.6% and 4.3% for the six months ended June 30, 2014 and 2013, respectively.

The credit agreement provides for a letter of credit fee equal to the then applicable working capital rate or then applicable revolver rate (each such rate as defined in the credit agreement) per annum for each letter of credit issued. In addition, we incur a commitment fee on the unused portion of each facility under the credit agreement, ranging from 0.375% to 0.50% per annum.

As of June 30, 2014, we had total borrowings outstanding under the credit agreement of $579.6 million, including $272.6 million outstanding on the revolving credit facility. In addition, we had outstanding letters of credit of $170.8 million. Subject to borrowing base limitations, the total remaining availability for borrowings and letters of credit was $874.6 million and $479.9 million at June 30, 2014 and December 31, 2013, respectively.

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

The credit agreement imposes financial covenants that require us to maintain certain minimum working capital amounts, a minimum combined interest coverage ratio, a maximum senior secured leverage ratio and a maximum total leverage ratio. We were in compliance with the foregoing covenants at June 30, 2014. The credit agreement also contains a representation whereby there can be no event or circumstance, either individually or in the aggregate, that has had or could reasonably be expected to have a Material Adverse Effect (as defined in the credit agreement). In addition, the credit agreement limits distributions by us to our unitholders to the amount of Available Cash (as defined in the partnership agreement).

8.0% Senior Notes

On February 14, 2013, we entered into a note purchase agreement with FS Energy and Power Fund (“FS Energy”), with respect to the issue and sale by us to FS Energy of an aggregate principal amount of $70.0 million unsecured 8.0% Senior Notes due 2018 (the “8.0% Notes”). The 8.0% Notes were issued in a private placement exempt from registration under the Securities Act of 1933, as amended (the “Securities Act”) and were not registered under the Securities Act or any state securities laws. Interest on the 8.0% Notes accrued from February 14, 2013 and was paid semi-annually on February 14 and August 14 of each year, beginning on August 14, 2013.

Closing of the offering occurred on February 14, 2013. The 8.0% Notes were sold to FS Energy at 97% of their face amount, resulting in net proceeds to us of approximately $67.9 million. Additionally, we separately paid fees and offering expenses. The discount of $2.1 million at issuance was accreted as additional interest. On February 15, 2013, we used the net proceeds from the offering, after paying fees and offering expenses, to finance a portion of our acquisition of all of the outstanding membership interests in Cascade Kelly and to pay related transaction costs.

7.75% Senior Notes

On December 23, 2013, we entered into a note purchase agreement with FS Energy and Power Fund, KARBO, L.P., Kayne Anderson Capital Income Partners (QP), L.P., Kayne Anderson Income Partners, L.P., Kayne Anderson Infrastructure Income Fund, L.P., Kayne Anderson Non-Traditional Investments, L.P., KANTI (QP), L.P. and Kayne Energy Credit Opportunities, L.P. as purchasers (the “Purchasers”), with respect to the issue and sale by us to the Purchasers of an aggregate principal amount of $80.0 million unsecured 7.75% Senior Notes due 2018 (the “7.75% Notes”). The 7.75% Notes were issued in a private placement exempt from registration under the Securities Act and were not registered under the Securities Act or any state securities laws. Interest was paid on the 7.75% Notes semi-annually on December 23 and June 23 of each year, beginning on June 23, 2014.

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

Exchange Rights Agreements

On June 19, 2014, we and GLP Finance (the “Issuers”) entered into a letter agreement (the “Exchange Rights Agreements”) with each of FS Energy and certain funds managed by Kayne Anderson Capital Advisors, L.P. pursuant to which the parties agreed to modifications to or waivers of certain of the provisions of the indentures governing the 8.0% Senior Notes and the 7.75% Senior Notes (collectively, the “Existing HY Notes”) for purposes of effecting the repayment of the Existing HY Notes with a portion of the proceeds of the Issuers’ private placement of the 6.25% Notes (defined below) and the subsequent issuance of a portion of the 6.25% Notes to the holders of the Existing HY Notes.

6.25% Senior Notes

On June 19, 2014, 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. 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. We used the net proceeds from the offering to repay a portion of the borrowings outstanding under our revolving credit facility and to repurchase or exchange all of our $150.0 million of the Existing HY Notes in accordance with the Exchange Rights Agreements, as follows: the principal amount of $70.0 million of the 8.0% Senior Notes and the principal amount of $80.0 million of the 7.75% Senior Notes, including premium payments but excluding accrued and unpaid interest. Specifically, we paid $40.2 million to the holders of the Existing HY Notes and exchanged the remaining $110.0 million of the Existing HY Notes for $116.0 million of the 6.25% Notes. The additional $6.0 million provided to the holders of the Existing HY Notes as a make-whole provision was treated as a discount to the 6.25% Notes included in senior notes in the accompanying balance sheet at June 30, 2014.

We accounted for the exchange of $110.0 million of the Existing HY Notes to the 6.25% Notes as a modification of debt rather than an extinguishment of debt in accordance with ASC 70-50, “Modification and Extinguishments,” as the cash flow effect on a present value basis was less than 10% which is not deemed a substantial modification of terms. As a result of the $40.0 million extinguishment of the remaining principal debt, we incurred expenses of $1.6 million associated with the write-off of a portion of the original issue discount and deferred financing fees. These expenses are included in interest expense in the accompanying statements of operations for the three and six months ended June 30, 2014.

Indenture

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

The 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

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Deferred Financing Fees

We incur bank fees related to our credit agreement and other financing arrangements. These deferred financing fees are amortized over the life of the credit agreement or other financing arrangements. We capitalized additional financing fees of $5.8 million for the three and six months ended June 30, 2014 associated with the issuance of our $375.0 million aggregate principal amount of our 6.25% senior notes due 2022 (see Note 6 of Notes to Consolidated Financial Statements). Amortization expenses of approximately $1.3 million and $1.7 million for the three months ended June 30, 2014 and 2013, respectively, and $2.6 million and $3.3 million for the six months ended June 30, 2014 and 2013, respectively are included in interest expense in the accompanying consolidated statements of operations. 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.

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, 2013. 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.

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.

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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 June 30, 2014, we had total borrowings outstanding under our credit agreement of $579.6 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 $5.8 million annually, assuming, however, that our indebtedness remained constant throughout the year.

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

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

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

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

In June 2014 and as a result of the issuance of our $375.0 million aggregate principal amount of our 6.25% senior notes due 2022 (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 is no longer probable. Therefore, we elected to de-designate our interest rate cap and discontinued the related hedge accounting for this instrument. Accordingly, at June 30, 2014, 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.

See Note 5 of Notes to Consolidated Financial Statements for additional information on our derivative instruments.

Commodity Risk

We hedge our exposure to price fluctuations with respect to refined petroleum products, renewable fuels, crude oil and gasoline blendstocks in storage and expected purchases and sales of these commodities. The derivative instruments utilized consist primarily of 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

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controlled trading program discussed below, we do not acquire and hold futures contracts or other derivative products for the purpose of speculating on price changes that might expose us to indeterminable losses.

While we seek to maintain a position that is substantially balanced within our product purchase activities, we may experience net unbalanced positions for short periods of time as a result of variances in daily sales and transportation and delivery schedules as well as other logistical issues inherent in the business, such as weather conditions. In connection with managing these positions, maintaining a constant presence in the marketplace and managing the futures market outlook for future anticipated inventories, which are necessary for our business, we engage in a controlled trading program for up to an aggregate of 250,000 barrels of products at any one point in time. Any derivatives not involved in a direct hedging activity are marked to market and recognized in the consolidated statement of income through cost of sales. In addition, because a portion of our crude oil business is conducted in Canadian dollars, we may use foreign currency derivatives to minimize the risks of unfavorable exchange rates. These instruments include foreign currency exchange contracts and forwards. In conjunction with entering into the commodity derivative, we may enter into a foreign currency derivative to hedge the resulting foreign currency risk. These foreign currency derivatives are generally short-term in nature and not designated for hedge accounting.

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

At June 30, 2014, 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)
	June 30, 2014			Effect of 10% Price Increase			Effect of 10% Price Decrease
Futures contracts	$	(2,605	)	$	(33,236	)	$	33,236
Swaps, options and other, net	228			(8,477		)	5,968
	$	(2,377	)	$	(41,713	)	$	39,204

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 June 30, 2014. 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 $20.2 million at June 30, 2014.

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

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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 Rule 13a-15(e) or 15d-15(e) of the Exchange Act) as of June 30, 2014. Based on this evaluation and the existence of material weaknesses in our internal control over financial reporting (discussed below), our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were not effective as of June 30, 2014. Based on our internal review, steps to remediate the material weaknesses 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, 2013, management concluded that material weaknesses existed in our internal control over reporting (as defined in Rule 13a-15(f) under the Exchange Act). Specifically, we were not performing timely and comprehensive reconciliations between our RINs on hand and our renewable volume obligation (RVO). Additionally, the integration and communication between our departments were not effective in identifying forward RIN purchase and sales contracts which were unfavorable. In addition, due to the inability to age and analyze the lag associated with certain accrued liabilities related to petroleum products, there was a design deficiency in the precision of our monitoring control over this liability. We also identified other deficiencies in our financial statement close process, which when aggregated, represented a material weakness in the financial statement close process. These control deficiencies contributed to material errors in the financial statements. Remedial actions are being implemented 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. Therefore, management has determined that we did not maintain effective internal control over financial reporting as of June 30, 2014.

In response, we have designed and substantially implemented the following remedial actions and continue to evaluate the changes in our internal control over financial reporting:

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

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

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

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

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

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

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· Hired additional experienced employees in the finance and accounting departments and expanded our internal audit function. In addition, we engaged a third-party consulting firm to support and assist in the evaluation of our internal controls over financial reporting.

Except as described above, there has not been any change in our internal control over financial reporting that occurred during the quarter ended June 30, 2014 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 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. 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 Securities and Exchange Commission (“SEC”) requesting information for relevant time periods primarily relating to our accounting for Renewable Identification Numbers and the recent 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 cooperate fully with, and have begun producing 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 our subsidiary, Cascade Kelly, which covers both the production of ethanol and transshipping of crude oil by our bio-refinery in Clatskanie, Oregon (the “Existing Permit”). This Modification proposed to limit the number of trains carrying crude oil that the bio-refinery can receive as part of our transloading operations. We submitted a request for a hearing to contest the Modification, which allows the Existing Permit to remain in effect pending this appeal. The Administrative Law Judge set a hearing for September 30, 2014. We also received a Pre-Enforcement Notice (“PEN”) letter dated January 10, 2014 from ODEQ claiming that we are in violation of the Existing Permit and informing us that ODEQ is considering a possible notice of violation and penalty assessment. In summary, the PEN asserts that we may have received, and may be receiving, more crude oil than the Existing Permit allows. On March 27, 2014, ODEQ issued us a civil penalty assessment (“CPA”) of $117,292. We have meritorious defenses to the Modification, the PEN and the CPA and will vigorously contest any actions that may be taken by ODEQ with respect to the foregoing.

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

We received from the Environmental Protection Agency (the “EPA”), by letters dated November 2, 2011 and March 29, 2012, reporting requirements and testing orders (collectively, the “Requests for Information”) for information under the Clean Air Act. The Requests for Information are part of an EPA investigation to determine whether we have violated sections of the Clean Air Act at certain of our terminal locations in New England with respect to residual oil and asphalt. On June 6, 2014, a Notice of Violation 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 are engaged in discussions with the EPA with respect to the alleged violations. We do not believe that a material violation has occurred nor do we believe any adverse determination in connection with the Notice of Violation would have a material impact on our operations.

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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, 2013, 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 June 30, 2014:

				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)
April 1 – April 30, 2014	—	—	—	—
May 1 – May 30, 2014	29,400	40.62	—	276,412
June 1 – June 30, 2014	15,400	40.82	—	291,812

(1) On May 7, 2009, the board of directors of our general partner announced that it authorized the repurchase of our common units for the purpose of meeting our general partner’s anticipated obligations to deliver common units under the Long-Term Incentive Plan (“LTIP”) and meeting the general partner’s obligations under existing employment agreements and other employment related obligations of the general partner. Our general partners is currently authorized to acquire up to 742,427 of our common units in the aggregate to be acquired over an extended period of time, consistent with the general partner’s obligations under the LTIP and employment agreements. Common units may be repurchased from time to time in open market transactions, including block purchases, or in privately negotiated transactions. Such authorized unit repurchases may be modified, suspended or terminated at any time, and are subject to price, economic and market conditions, applicable legal requirements and available liquidity.

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Item 6. Exhibits

2.1**	—	Membership Interest Purchase Agreement, dated as of January 22, 2013, between JH Kelly Holdings LLC and Global Partners LP (incorporated herein by reference to Exhibit 2.1 to the Current Report on Form 8-K filed on February 22, 2013).

3.1	—	Third Amended and Restated Agreement of Limited Partnership of Global Partners LP dated as of December 9, 2009 (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K filed on December 15, 2009).

4.1	—	Indenture, dated as of June 24, 2014, among the Issuers, the Guarantors, and Deutsche Bank Trust Company Americas, as trustee (incorporated herein by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on June 25, 2014).

4.2	—	Registration Rights Agreement, dated June 24, 2014, among the Issuers, the Guarantors and the Initial Purchasers (incorporated herein by reference to Exhibit 4.2 to the Current Report on Form 8-K filed on June 25, 2014).

10.1	—	Purchase Agreement, dated June 19, 2014 among the Issuers, the Guarantors and the Initial Purchasers (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on June 25, 2014).

10.2	—	Exchange Rights Agreement, dated June 19, 2014 by and among Global Partners LP, GLP Finance Corp. and FS Energy and Power Fund (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on June 25, 2014).

10.3	—	Exchange Rights Agreement, dated June 19, 2014 by and among Global Partners LP. GLP Finance Corp., FS Energy and Power Fund, Kayne Anderson Non-Traditional Investments, L.P., Kanti (QP), L.P., Kayne Anderson Capital Income Partners (QP), L.P., Kayne Anderson Income Partners, L.P., Kayne Anderson Infrastructure Income Fund, L.P., Kayne Energy Credit Opportunities, L.P. and Karbo L.P. (incorporated herein by reference to Exhibit 10.3 to the Current Report on Form 8-K filed on June 25, 2014).

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.

** 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.

* Filed herewith.

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

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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: August 8, 2014		By:	/s/ Eric Slifka
			Eric Slifka
			President and Chief Executive Officer
			(Principal Executive Officer)


Dated: August 8, 2014		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**	—	Membership Interest Purchase Agreement, dated as of January 22, 2013, between JH Kelly Holdings LLC and Global Partners LP (incorporated herein by reference to Exhibit 2.1 to the Current Report on Form 8-K filed on February 22, 2013).

3.1	—	Third Amended and Restated Agreement of Limited Partnership of Global Partners LP dated as of December 9, 2009 (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K filed on December 15, 2009).

4.1	—	Indenture, dated as of June 24, 2014, among the Issuers, the Guarantors, and Deutsche Bank Trust Company Americas, as trustee (incorporated herein by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on June 25, 2014).

4.2	—	Registration Rights Agreement, dated June 24, 2014, among the Issuers, the Guarantors and the Initial Purchasers (incorporated herein by reference to Exhibit 4.2 to the Current Report on Form 8-K filed on June 25, 2014).

10.1	—	Purchase Agreement, dated June 19, 2014 among the Issuers, the Guarantors and the Initial Purchasers (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on June 25, 2014).

10.2	—	Exchange Rights Agreement, dated June 19, 2014 by and among Global Partners LP, GLP Finance Corp. and FS Energy and Power Fund (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on June 25, 2014).

10.3	—	Exchange Rights Agreement, dated June 19, 2014 by and among Global Partners LP. GLP Finance Corp., FS Energy and Power Fund, Kayne Anderson Non-Traditional Investments, L.P., Kanti (QP), L.P., Kayne Anderson Capital Income Partners (QP), L.P., Kayne Anderson Income Partners, L.P., Kayne Anderson Infrastructure Income Fund, L.P., Kayne Energy Credit Opportunities, L.P. and Karbo L.P. (incorporated herein by reference to Exhibit 10.3 to the Current Report on Form 8-K filed on June 25, 2014).

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.

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