Edgar Filing: GLOBAL PARTNERS LP

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2013

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 x 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 x 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 x

The issuer had 27,430,563 common units outstanding as of August 5, 2013.

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TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION

	Item 1. Financial Statements		1

		Consolidated Balance Sheets as of June 30, 2013 and December 31, 2012	1

		Consolidated Statements of Income for the three and six months ended June 30, 2013 and 2012	2

		Consolidated Statements of Comprehensive Income for the three and six months ended June 30, 2013 and 2012	3

		Consolidated Statements of Cash Flows for the six months ended June 30, 2013 and 2012	4

		Consolidated Statement of Partners’ Equity for the six months ended June 30, 2013	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		61

	Item 4. Controls and Procedures		63

PART II. OTHER INFORMATION			65

	Item 1. Legal Proceedings		65

	Item 1A. Risk Factors		66

	Item 6. Exhibits		66

SIGNATURES			68

INDEX TO EXHIBITS			69

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Item 1. Financial Statements

GLOBAL PARTNERS LP

CONSOLIDATED BALANCE SHEETS

(In thousands, except unit data)

(Unaudited)

	June 30,			December 31,
	2013			2012
Assets
Current assets:
Cash and cash equivalents	$	9,673		$	5,977
Accounts receivable, net	745,846			696,762
Accounts receivable—affiliates	1,400			1,307
Inventories	354,161			634,667
Brokerage margin deposits	21,954			54,726
Fair value of forward fixed price contracts	2,022			48,062
Prepaid expenses and other current assets	45,179			65,432
Total current assets	1,180,235			1,506,933

Property and equipment, net	787,717			712,322
Goodwill	107,579			32,326
Intangible assets, net	128,932			60,822
Other assets	18,832			17,349
Total assets	$	2,223,295		$	2,329,752
Liabilities and partners’ equity
Current liabilities:
Accounts payable	$	764,061		$	759,698
Working capital revolving credit facility—current portion	—			83,746
Term loan	115,000			—
Environmental liabilities—current portion	4,286			4,341
Trustee taxes payable	75,789			91,494
Accrued expenses and other current liabilities	50,205			71,442
Obligations on forward fixed price contracts	8,730			34,474
Total current liabilities	1,018,071			1,045,195
Working capital revolving credit facility—less current portion	211,500			340,754
Revolving credit facility	374,700			422,000
Senior notes	68,058			—
Environmental liabilities—less current portion	38,380			39,831
Other long-term liabilities	41,136			45,511
Total liabilities	1,751,845			1,893,291
Partners’ equity
Global Partners LP equity:
Common unitholders (27,430,563 units issued and 27,393,786 outstanding at June 30, 2013 and 27,430,563 units issued and 27,310,648 outstanding at December 31, 2012)	444,952			456,538
General partner interest (0.83% interest with 230,303 equivalent units outstanding at June 30, 2013 and December 31, 2012)	(332		)	(407		)
Accumulated other comprehensive loss	(14,123		)	(19,670		)
Total Global Partners LP equity	430,497			436,461
Noncontrolling interest	40,953			—
Total partners’ equity	471,450			436,461
Total liabilities and partners’ equity	$	2,223,295		$	2,329,752

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

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GLOBAL PARTNERS LP

CONSOLIDATED STATEMENTS OF INCOME

(In thousands, except per unit data)

(Unaudited)

		Three Months Ended June 30,						Six Months Ended June 30,
		2013			2012			2013			2012

Sales		$	4,771,756		$	3,916,063		$	10,360,946		$	7,891,544
Cost of sales		4,673,899			3,825,388			10,167,237			7,745,550
Gross profit		97,857			90,675			193,709			145,994

Costs and operating expenses:
Selling, general and administrative expenses		27,077			24,036			53,837			46,503
Operating expenses		47,367			37,138			90,707			60,496
Amortization expense		5,677			2,288			10,053			3,862
Total costs and operating expenses		80,121			63,462			154,597			110,861

Operating income		17,736			27,213			39,112			35,133

Interest expense		(9,024		)	(9,148		)	(17,940		)	(18,468		)

Income before income tax benefit		8,712			18,065			21,172			16,665

Income tax benefit		—			450			1,875			450

Net income		8,712			18,515			23,047			17,115

Net (income) loss attributable to noncontrolling interest		(18		)	—			472			—

Net income attributable to Global Partners LP		8,694			18,515			23,519			17,115

Less:	General partner’s interest in net income, including incentive distribution rights	(796		)	(309		)	(1,602		)	(417		)

Limited partners’ interest in net income		$	7,898		$	18,206		$	21,917		$	16,698

Basic net income per limited partner unit		$	0.29		$	0.67		$	0.80		$	0.66

Diluted net income per limited partner unit		$	0.29		$	0.66		$	0.80		$	0.65

Basic weighted average limited partner units outstanding		27,394			27,376			27,358			25,466

Diluted weighted average limited partner units outstanding		27,491			27,549			27,454			25,638

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

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GLOBAL PARTNERS LP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In thousands)

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013		2012

Net income	$	8,712		$	18,515		$	23,047	$	17,115
Other comprehensive income (loss):
Change in fair value of cash flow hedges	2,049			(42		)	3,522		689
Change in pension liability	1,259			(90		)	2,025		208
Total other comprehensive income (loss)	3,308			(132		)	5,547		897
Comprehensive income	12,020			18,383			28,594		18,012
Comprehensive (income) loss attributable to noncontrolling interest	(18		)	—			472		—
Comprehensive income attributable to Global Partners LP	$	12,002		$	18,383		$	29,066	$	18,012

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,
	2013			2012
Cash flows from operating activities
Net income	$	23,047		$	17,115
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	36,238			21,397
Amortization of deferred financing fees	3,318			2,710
Amortization of senior notes discount	158			—
Bad debt expense	1,569			180
Stock-based compensation expense	104			(46		)
Deferred income taxes	—			450
Curtailment gain	—			(469		)
Changes in operating assets and liabilities, exclusive of business combinations:
Accounts receivable	(48,354		)	190,344
Accounts receivable — affiliate	(93		)	988
Inventories	281,023			171,479
Broker margin deposits	32,772			14,341
Prepaid expenses, all other current assets and other assets	15,615			4,863
Accounts payable	1,609			(205,314		)
Trustee taxes payable	(15,705		)	(1,578		)
Change in fair value of forward fixed price contracts	20,296			(3,296		)
Accrued expenses, all other current liabilities and other long-term liabilities	(23,885		)	3,136
Net cash provided by operating activities	327,712			216,300

Cash flows from investing activities
Acquisitions	(185,251		)	(181,898		)
Capital expenditures	(30,069		)	(19,730		)
Proceeds from sale of property and equipment	2,413			4
Net cash used in investing activities	(212,907		)	(201,624		)

Cash flows from financing activities
Payments on working capital revolving credit facility	(213,000		)	(179,200		)
(Payments on) borrowings from revolving credit facility	(47,300		)	192,000
Borrowings from term loan	115,000			—
Proceeds from senior notes, net of discount	67,900			—
Repurchase of common units	—			(2,152		)
Repurchased units withheld for tax obligations	(2,086		)	(96		)
Noncontrolling interest capital contribution	1,425			—
Distributions to partners	(33,048		)	(24,995		)
Net cash used in financing activities	(111,109		)	(14,443		)

Increase in cash and cash equivalents	3,696			233
Cash and cash equivalents at beginning of period	5,977			4,328
Cash and cash equivalents at end of period	$	9,673		$	4,561

Supplemental information
Cash paid during the period for interest	$	15,544		$	18,561
Non-cash investing activities (see Note 17)

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

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GLOBAL PARTNERS LP

CONSOLIDATED STATEMENTS OF PARTNERS’ EQUITY

(In thousands)

(Unaudited)

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

Balance at December 31, 2012	$	456,538		$	(407	)	$	(19,670	)	$	—		$	436,461
Net income	21,917			1,602			—			(472		)	23,047
Noncontrolling interest capital contribution	—			—			—			41,425			41,425
Other comprehensive income	—			—			5,547			—			5,547
Stock-based compensation	104			—			—			—			104
Distributions to partners	(31,615		)	(1,527		)	—			—			(33,142		)
Repurchased units withheld for tax obligation	(2,086		)	—			—			—			(2,086		)
Phantom unit dividends	94			—			—			—			94
Balance at June 30, 2013	$	444,952		$	(332	)	$	(14,123	)	$	40,953		$	471,450

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, 2013, the Partnership had the following wholly owned subsidiaries: Global Companies LLC, Glen Hes Corp., Global Montello Group Corp. (“GMG”), Chelsea Sandwich LLC, Global Energy Marketing LLC, Alliance Energy LLC, Bursaw Oil LLC, GLP Finance Corp., Global Energy Marketing II LLC, Global CNG LLC and Cascade Kelly Holdings LLC. Global GP LLC, the Partnership’s general partner (the “General Partner”) manages the Partnership’s operations and activities and employs its officers and substantially all of its personnel, except for its gasoline station and convenience store employees and certain union personnel who are employed by GMG.

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

On March 1, 2012, the Partnership acquired from AE Holdings Corp. (“AE Holdings”) 100% of the outstanding membership interests in Alliance Energy LLC (“Alliance”) (see Note 2). Prior to the closing of the acquisition, Alliance was wholly owned by AE Holdings, which is approximately 95% owned by members of the Slifka family. No member of the Slifka family owned a controlling interest in AE Holdings, nor currently owns a controlling interest in the General Partner. Three independent directors of the General Partner’s board of directors serve on a conflicts committee. The conflicts committee unanimously approved the Alliance acquisition and received advice from its independent counsel and independent financial adviser.

On February 1, 2013, the Partnership acquired a 60% membership interest in Basin Transload LLC (“Basin Transload”), and on February 15, 2013, the Partnership acquired 100% of the membership interests in Cascade Kelly Holdings LLC (“Cascade Kelly”). See Note 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, 2013, affiliates of the General Partner, including its directors and executive officers, owned 11,546,993 common units, representing a 42.1% 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 income for the six months ended June 30, 2013. The Partnership consolidated the June 30, 2013 balance sheet of Basin Transload because the Partnership controls the entity. The accompanying consolidated financial statements as of June 30, 2013 and December 31, 2012 and for the three and six months ended June 30, 2013 and 2012 reflect the accounts of the Partnership. 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, 2012 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, 2013 are not necessarily indicative of the results of operations that will be realized for the entire year ending December 31, 2013. The consolidated balance sheet at December 31, 2012 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, 2012.

Due to the nature of the Partnership’s business and its customers’ 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 income.

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1. Organization and Basis of Presentation (continued)

Concentration of Risk

The following table presents the Partnership’s product sales as a percentage of total sales for the periods presented:

	Three Months Ended June 30,		Six Months Ended June 30,
	2013	2012	2013	2012
Gasoline sales: gasoline and gasoline blendstocks such as ethanol and naphtha	59%	74%	56%	66%
Distillates (home heating oil, diesel and kerosene), residual oil, crude oil, natural gas and propane sales	41%	26%	44%	34%
Total	100%	100%	100%	100%

The Partnership had two significant customers, ExxonMobil Corporation (“ExxonMobil”) and Phillips 66 (“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. The Partnership had one significant customer, ExxonMobil, which accounted for approximately 17% and 16% of total sales for the three and six months ended June 30, 2012, respectively.

Note 2. Business Combinations

2013 Acquisitions

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

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 2. Business Combinations (continued)

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

Assets purchased:
Accounts receivable	$	2,003
Prepaid expenses	68
Property and equipment	28,016
Intangibles	78,163
Total identifiable assets purchased	108,250
Liabilities assumed:
Accounts payable	(1,326		)
Total liabilities assumed	(1,326		)
Net identifiable assets acquired	106,924
Noncontrolling interest	(40,000		)
Goodwill	24,148
Net assets acquired	$	91,072

Management is in the process of evaluating the purchase price accounting. The Partnership engaged a third-party valuation firm to assist in the valuation of the Partnership’s interest in Basin Transload’s property and equipment and intangibles. Although the valuation has commenced, it remains in the early stages of progress. Therefore, management continues to rely on its original estimate of fair value for property and equipment in the table above of $28.0 million which was developed by management based on their estimates, assumptions and acquisition history. The fair value of $78.2 million assigned to the intangibles, primarily customer relationships, was also estimated by management based on their estimates, assumptions and acquisition history and will be updated upon completion of the Partnership’s third-party valuation firm.

The fair value of the noncontrolling interest has been primarily developed by management based on the fair value of the acquired business as a whole, reduced by the consideration paid by management to obtain control. This fair value of the business was estimated based on the fair value of Basin Transload’s net assets and applying a reasonable control premium.

The fair values of the remaining Basin Transload assets and liabilities noted above approximate their carrying values at February 1, 2013. It is possible that once the Partnership receives the completed valuations on the property and equipment, intangible assets and noncontrolling interest, the final purchase price accounting may be different than what is presented above.

The preliminary purchase price for the acquisition was allocated to assets acquired and liabilities assumed based on their estimated fair values. The Partnership then allocated the purchase price in excess of net tangible assets acquired to identifiable intangible assets, based upon on their estimates and assumptions. Any excess purchase price over the fair value of the net tangible and intangible assets acquired was allocated to goodwill.

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

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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 over five years. Amortization expense amounted to $3.9 million and $6.5 million for the three and six months ended June 30, 2013, respectively. The estimated remaining amortization expense for intangible assets acquired in connection with the acquisition for each of the five succeeding years and thereafter is as follows (in thousands):

2013 (7/1/13 – 12/31/13)	$	7,800
2014	15,600
2015	15,600
2016	15,600
2017	15,600
Thereafter	1,300
Total	$	71,500

The $24.1 million of goodwill was assigned to the Wholesale reporting unit. The goodwill recognized is attributed to the unique origin of the acquired locations through which the Partnership’s customers can efficiently supply cost-competitive crude oil to destinations on the East and West Coasts. The goodwill is deductible for income tax purposes.

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 8.00% senior notes due 2018 (see Note 6). The transaction includes 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.

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 2. Business Combinations (continued)

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

Assets purchased:
Accounts receivable	$	296
Inventory	517
Prepaid expenses	96
Property and equipment	45,100
Total identifiable assets purchased	46,009
Liabilities assumed:
Accounts payable	(1,428		)
Other current liabilities	(1,507		)
Total liabilities assumed	(2,935		)
Net identifiable assets acquired	43,074
Goodwill	51,105
Net assets acquired	$	94,179

Management is in the process of evaluating the purchase price accounting. The Partnership engaged a third-party valuation firm to assist in the valuation of Cascade Kelly’s property and equipment and possible intangibles. Although the valuation has commenced, it remains in the early stages of progress. Therefore, management continues to rely on its original estimate of fair value for property and equipment in the table above of $45.1 million which was developed by management based on their estimates, assumptions and acquisition history.

The fair values of the remaining Cascade Kelly assets and liabilities noted above approximate their carrying values at February 15, 2013. It is possible that once the Partnership receives the completed valuations on the property and equipment, the final purchase price accounting may be different than what is presented above.

The preliminary purchase price for the acquisition was allocated to assets acquired and liabilities assumed based on their estimated fair values. The Partnership then allocated the purchase price in excess of net tangible assets acquired to identifiable intangible assets, if any, based upon on their estimates and assumptions. Any excess purchase price over the fair value of the net tangible and intangible assets acquired was allocated to goodwill.

The $51.1 million of goodwill was assigned to the Wholesale reporting unit. The goodwill recognized is primarily attributed to the crude oil facility and, to a lesser extent, the ethanol plant, which will strategically enhance the Partnership’s network of origin and destination assets and extend the Partnership’s virtual pipeline to the West Coast. The goodwill is deductible for income tax purposes.

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 2. Business Combinations (continued)

2012 Acquisition

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

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

The purchase price for the acquisition was allocated to assets acquired and liabilities assumed based on their estimated fair values with the exception of environmental liabilities which were recorded on an undiscounted basis (see Note 11). The Partnership then allocated the purchase price in excess of net tangible assets acquired to identifiable intangible assets, based upon a valuation from an independent third party. Any excess purchase price over the fair value of the net tangible and intangible assets acquired was allocated to goodwill and assigned to the Gasoline Distribution and Station Operations reporting unit.

Goodwill — The following table presents a summary roll forward of the Partnership’s goodwill at June 30, 2013 (in thousands):

	Goodwill at				Goodwill at
	December 31,		2013		June 30,
	2012		Additions		2013
Acquisition of Alliance (1)	$	31,151	$	—	$	31,151
Acquisition of gasoline stations from Mutual Oil Company (1)	1,175		—		1,175
Acquisition of 60% interest in Basin Transload (2)	—		24,148		24,148
Acquisition of Cascade Kelly (2)	—		51,105		51,105
Total	$	32,326	$	75,253	$	107,579

(1) Goodwill allocated to the Gasoline Distribution and Station Operations reporting unit

(2) Goodwill allocated to the Wholesale reporting unit

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 2. Business Combinations (continued)

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 income for the six months ended June 30, 2013.

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

	Six Months
	Ended
	June 30, 2012

Sales	$	8,135,917
Net income (loss)	$	(5,077	)
Basic net income per limited partner unit	$	(0.19	)
Diluted net income per limited partner unit	$	(0.19	)

The Partnership’s 60% interest in Basin Transload’s sales and net loss included in the Partnership’s consolidated operating results from February 1, 2013, the acquisition date, through the period ended June 30, 2013 were $4.0 million and $0.7 million, respectively. Cascade Kelly’s sales and net loss included in the Partnership’s consolidated operating results from February 15, 2013, the acquisition date, through the period ended June 30, 2013 were $4.7 million and $0.8 million, respectively.

Note 3. Net Income Per Limited Partner Unit

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

At June 30, 2013 and December 31, 2012, common units outstanding as reported in the accompanying consolidated financial statements excluded 36,777 and 119,915 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 income per limited partner unit (basic and diluted).

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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

The following table provides a reconciliation of net income and the assumed allocation of net income to the limited partners’ interest for purposes of computing net income per limited partner unit for the three and six months ended June 30, 2013 and 2012 (in thousands, except per unit data):


	Three Months Ended June 30, 2013											Three Months Ended June 30, 2012
	Total			Limited Partner Interest			General Partner Interest			IDRs		Total		Limited Partner Interest		General Partner Interest			IDRs
Numerator:
Net income attributable to Global Partners LP	$	8,694		$	7,898		$	796		$	—	$	18,515	$	18,206	$	309		$	—

Declared distribution	$	16,975		$	16,116		$	135		$	724	$	14,781	$	14,401	$	121		$	259
Assumed allocation of undistributed net income	(8,281		)	(8,218		)	(63		)	—		3,734		3,805		(71		)	—
Assumed allocation of net income	$	8,694		$	7,898		$	72		$	724	$	18,515	$	18,206	$	50		$	259

Denominator:
Basic weighted average limited partner units outstanding				27,394										27,376
Dilutive effect of phantom units				97										173
Diluted weighted average limited partner units outstanding				27,491										27,549

Basic net income per limited partner unit				$	0.29									$	0.67
Diluted net income per limited partner unit				$	0.29									$	0.66

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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


	Six Months Ended June 30, 2013											Six Months Ended June 30, 2012
	Total			Limited Partner Interest			General Partner Interest			IDRs		Total			Limited Partner Interest			General Partner Interest			IDRs
Numerator:
Net income attributable to Global Partners LP (1)	$	23,519		$	21,917		$	1,602		$	—	$	17,115		$	16,698		$	417		$	—

Declared distribution	$	33,771		$	32,095		$	269		$	1,407	$	28,767		$	28,117		$	236		$	414
Adjustment to distribution in connection with the Alliance acquisition (2)	—			—			—			—		(1,929		)	(1,929		)	—			—
Adjusted declared distribution	33,771			32,095			269			1,407		26,838			26,188			236			414
Assumed allocation of undistributed net income	(10,252		)	(10,178		)	(74		)	—		(9,723		)	(9,490		)	(233		)	—
Assumed allocation of net income	$	23,519		$	21,917		$	195		$	1,407	$	17,115		$	16,698		$	3		$	414

Denominator:
Basic weighted average limited partner units outstanding				27,358											25,466
Dilutive effect of phantom units				96											172
Diluted weighted average limited partner units outstanding				27,454											25,638

Basic net income per limited partner unit				$	0.80										$	0.66
Diluted net income per limited partner unit				$	0.80										$	0.65

(1) Calculation includes the effect of the March 1, 2012 issuance of 5,850,000 common units in connection with the acquisition of Alliance. As a result, the general partner interest was 0.83% for the six months ended June 30, 2013 and, based on a weighted average, 0.95% for the six months ended June 30, 2012.

(2) In connection with the acquisition of Alliance on March 1, 2012 and the issuance of 5,850,000 common units, the Contribution Agreement provided that any declared distribution for the first quarter of 2012 reflect the seller’s actual period of ownership during that quarter. The payment by the seller of $1.9 million reflects the timing of the transaction (March 1), the seller’s 31 days of actual unit ownership in the 91 days of the quarter and the net receipt by seller ($1.0 million) of a pro-rated portion of the quarterly cash distribution of $0.50 per unit paid on the issued 5,850,000 common units.

On April 24, 2013, the board of directors of the General Partner declared a quarterly cash distribution of $0.5825 per unit for the period from January 1, 2013 through March 31, 2013. On July 23, 2013, the board of directors of the General Partner declared a quarterly cash distribution of $0.5875 per unit for the period from April 1, 2013 through June 30, 2013. 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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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 4. Inventories

Except for its convenience store inventory, the Partnership hedges substantially all of its inventory, primarily through futures contracts. These futures contracts are entered into when inventory is purchased and are designated as fair value hedges against the inventory on a specific barrel basis. Changes in the fair value of these contracts, as well as the offsetting gain or loss on the hedged inventory item, are recognized in earnings as an increase or decrease in cost of sales. All hedged inventory is valued using the lower of cost, as determined by specific identification, or market. Prior to sale, hedges are removed from specific barrels of inventory, and the then unhedged inventory is sold and accounted for on a first-in, first-out basis. In addition, the Partnership has convenience store inventory which is carried at the lower of historical cost or market. Inventory from Cascade Kelly was nominal at June 30, 2013 and is carried at the lower of cost or market.

Inventories consisted of the following (in thousands):

	June 30,		December 31,
	2013		2012
Distillates: home heating oil, diesel and kerosene	$	91,271	$	235,029
Gasoline	76,070		144,269
Gasoline blendstocks	77,261		139,316
Residual oil and crude oil	100,184		109,423
Propane and other	2,568		—
Convenience store inventory	6,807		6,630
Total	$	354,161	$	634,667

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 $188.5 million and $120.9 million at June 30, 2013 and December 31, 2012, respectively. Negative exchange balances are accounted for as accounts payable and amounted to $201.9 million and $139.5 million at June 30, 2013 and December 31, 2012, respectively. Exchange transactions are valued using current inventory levels.

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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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(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, 2013:

	Units (1)			Unit of Measure

Futures Contracts
Long	10,673			Thousands of barrels
Short	(13,471		)	Thousands of barrels

Natural Gas Contracts
Long	6,643			Thousands of decatherms
Short	(6,643		)	Thousands of decatherms

Interest Rate Collar	$	100.0		Millions of U.S. dollars
Interest Rate Swap	$	100.0		Millions of U.S. dollars
Interest Rate Cap	$	100.0		Millions of U.S. dollars

Foreign Currency Derivatives
Open Forward Exchange Contracts (2)	$	20.2		Millions of Canadian dollars
	$	19.2		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”) $1.0521 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, 2013 and December 31, 2012. These contracts remain open until their contract end date. The daily settlement of these futures contracts is accomplished through the use of brokerage margin deposit accounts.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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 income for the three and six months ended June 30, 2013 and 2012 (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

2013

2012

2013

2012

Futures contracts

Cost of sales

30,486

80,430

20,101

(9,448

)

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,

Hedged Relationships

Income on Hedged Items

2013

2012

2013

2012

Inventories

Cost of sales

(29,974

)

(80,354

)

(19,578

)

9,602

Cash Flow Hedges

The Partnership utilizes various interest rate derivative instruments to hedge variable interest rate on its debt. These derivative instruments are designated as cash flow hedges of the underlying debt. To 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 expires on October 2, 2013, is 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 5. Derivative Financial Instruments (continued)

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, 2013 and December 31, 2012 (in thousands):

		June 30,		December 31,
Derivatives Designated as		2013		2012
Hedging Instruments	Balance Sheet Location	Fair Value		Fair Value

Asset derivatives
Interest rate cap	Other assets	$	92	$	35

Liability derivatives
Interest rate collar	Other long-term liabilities	$	642	$	1,868
Interest rate swap	Other long-term liabilities	9,295		11,534
Total liability derivatives		$	9,937	$	13,402

The following table presents the amount of net gains and losses from derivatives involved in cash flow hedging relationships recognized in the Partnership’s consolidated statements of income and partners’ equity for the three and six months ended June 30, 2013 and 2012 (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	2013		2012			2013		2012		2013		2012			2013		2012

Interest rate collar	$	611	$	545		$	—	$	—	$	1,226	$	860		$	—	$	—
Interest rate swap	1,376		(383		)	—		—		2,239		56			—		—
Interest rate cap	62		(204		)	—		—		57		(227		)	—		—
Total	$	2,049	$	(42	)	$	—	$	—	$	3,522	$	689		$	—	$	—

Ineffectiveness related to the interest rate collar and the interest rate swap is recognized as interest expense and was immaterial for the three and six months ended June 30, 2013 and 2012. The effective portion related to the interest rate collar that was originally reported in other comprehensive income and reclassified to earnings was $0.7 million and $0.6 million for the three months ended June 30, 2013 and 2012, respectively, and $1.3 million and $1.2 million for the six months ended June 30, 2013 and 2012, respectively. None of the effective portion related to the interest rate cap that was originally reported in other comprehensive income was reclassified into earnings for the three and six months ended June 30, 2013 and 2012.

Other Derivative Activity

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 5. Derivative Financial Instruments (continued)

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

The Partnership also markets and sells natural gas and propane by entering into forward purchase commitments for natural gas and propane 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, 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 sheet. 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’s 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, 2013 and December 31, 2012. These contracts remain open until their contract end date. The daily settlement of these futures contracts is accomplished through the use of brokerage margin deposit accounts.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(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, 2013 and December 31, 2012 (in thousands):

			June 30,		December 31,
		Balance Sheet	2013		2012

Summary of Other Derivatives	Item Pertains to	Location	Fair Value		Fair Value


Asset Derivatives

Forward purchase commitments	Gasoline and Gasoline Blendstocks	(1)	$	636	$	131
	Crude Oil	(1)	—		15,127
	Residual Oil	(1)	—		285
Total forward purchase commitments			636		15,543

Forward sales commitments	Gasoline and Gasoline Blendstocks	(1)	407		30,928
	Distillates	(1)	847		—
	Natural Gas	(1)	50		1,591
	Propane	(1)	82		—
Total forward sales commitments			1,386		32,519
Total forward fixed price contracts			2,022		48,062

Foreign currency forward contract	Foreign Denominated Sales	(2)	380		145
Total asset derivatives			$	2,402	$	48,207

Liability Derivatives
Forward purchase commitments	Gasoline and Gasoline Blendstocks	(3)	$	116	$	27,604
	Crude Oil	(3)	7,675		—
	Residual Oil	(3)	277		—
	Distillates	(3)	516		2,171
	Natural Gas	(3)	49		1,576
	Propane	(3)	97		—
Total forward purchase commitments			8,730		31,351

Forward sales commitments	Gasoline and Gasoline Blendstocks	(3)	—		173
	Distillates	(3)	—		2,950
Total forward sales commitments			—		3,123
Total obligations on forward fixed price contracts			$	8,730	$	34,474

(1) Fair value of forward fixed price contracts

(2) Prepaid expenses and other current assets

(3) Obligations on forward fixed price contracts

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 5. Derivative Financial Instruments (continued)

The following table presents the amount of gains and losses from derivatives not involved in a hedging relationship recognized in the Partnership’s consolidated statements of income for the three and six months ended June 30, 2013 and 2012 (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	2013		2012			2013		2012

Product contracts	Cost of sales	$	2,981	$	2,872		$	3,647	$	4,604
Foreign currency contracts	Cost of sales	555		(39		)	234		(39		)
Total		$	3,536	$	2,833		$	3,881	$	4,565

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

The Partnership entered into an Amended and Restated Credit Agreement dated May 14, 2010, as amended (the “Credit Agreement”). Total available commitments under the Credit Agreement are $1.615 billion. The Credit Agreement will mature on May 14, 2015.

As of June 30, 2013, there were three 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;

· a $500.0 million revolving credit facility to be used for acquisitions and general corporate purposes; and

· a $115.0 million term loan that will mature on January 31, 2014.

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 $250.0 million, in the aggregate, for a total credit facility of up to $1.865 billion. Any such request for an increase by the Partnership must be in a minimum amount of $5.0 million. The Partnership cannot provide assurance, however, that its lending group will agree to fund any request by the Partnership for additional amounts in excess of the total available commitments of $1.615 billion.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 6. Debt (continued)

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 an aggregate amount equal to the lesser of (a) $35.0 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 $1.615 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).

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

Commencing November 16, 2012, borrowings under the working capital revolving credit facility bear 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 Credit Agreement). From January 1, 2012 through November 15, 2012, borrowings under the working capital revolving credit facility bore interest at (1) the Eurodollar rate plus 2.50% to 3.00%, (2) the cost of funds rate plus 2.50% to 3.00%, or (3) the base rate plus 1.50% to 2.00%, each depending on the pricing level provided in the Credit Agreement, which in turn depended upon the Utilization Amount (as defined in the Credit Agreement).

Commencing November 16, 2012, borrowings under the revolving credit facility bear 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 Credit Agreement). From January 1, 2012 through November 15, 2012, borrowings under the revolving credit facility bore interest at (1) the Eurodollar rate plus 3.00% to 3.875%, (2) the cost of funds rate plus 3.00% to 3.875%, or (3) the base rate plus 2.00% to 2.875%, each depending on the pricing level provided in the Credit Agreement, which in turn depended upon the Combined Total Leverage Ratio (as defined in the Credit Agreement).

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Note 6. Debt (continued)

Borrowings under the term loan bear interest at either the Eurodollar rate or the cost of funds rate, in each case plus 3.50%, or the base rate plus 2.50%.

The average interest rates for the Credit Agreement were 4.5% and 4.1% for the three months ended June 30, 2013 and 2012, respectively, and 4.3% and 4.1% for the six months ended June 30, 2013 and 2012, respectively.

The Partnership currently has a zero premium interest rate collar, an interest rate swap and an interest rate cap, all of which are 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 Partnership incurs a letter of credit fee of 2.00% — 2.50% 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 $211.5 million and $340.8 million at June 30, 2013 and December 31, 2012, respectively, representing the amounts expected to be outstanding during the entire year. In addition, the Partnership classifies a portion of its working capital revolving credit facility as a current liability because it repays amounts outstanding and reborrows funds based on its working capital requirements. The current portion of the working capital revolving credit facility was approximately $0 and $83.7 million at June 30, 2013 and December 31, 2012, respectively, representing the amounts the Partnership expects to pay down during the course of the year.

As of June 30, 2013, the Partnership had total borrowings outstanding under the Credit Agreement of $701.2 million, including $374.7 million outstanding on the revolving credit facility and $115.0 million outstanding on the term loan which was used to acquire a 60% membership interest in Basin Transload and a portion of all of the outstanding membership interests in Cascade Kelly. In addition, the Partnership had outstanding letters of credit of $301.9 million. Subject to borrowing base limitations, the total remaining availability for borrowings and letters of credit was $611.9 million and $218.9 million at June 30, 2013 and December 31, 2012, respectively.

The Credit Agreement is secured by substantially all of the assets of the Partnership and the Partnership’s wholly owned subsidiaries and is guaranteed by the General Partner. The Credit Agreement imposes certain requirements 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 limitations on the Partnership’s ability to grant liens, make certain loans or investments, incur additional indebtedness or guarantee other indebtedness, make any material change to the nature of the Partnership’s business or undergo a fundamental change, make any material dispositions, acquire another company, enter into a merger, consolidation, sale leaseback transaction or purchase of assets, or make capital expenditures in excess of specified levels.

The Credit Agreement imposes financial covenants that require the Partnership to maintain certain minimum working capital amounts, capital expenditure limits, 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, 2013. The Credit Agreement also contains a representation whereby there can be no event or circumstance, either individually or in the aggregate, that has had or could reasonably be expected to have a Material Adverse Effect (as defined in the Credit Agreement). In addition, the Credit Agreement limits distributions by the Partnership to its unitholders to the amount of the Partnership’s Available Cash (as defined in its partnership agreement).

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Note 6. Debt (continued)

Senior Notes

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

Closing of the offering occurred on February 14, 2013. The Notes were sold to FS Energy at 97% of their face amount, resulting in net proceeds to the Partnership of approximately $67.9 million. Additionally, the Partnership separately paid fees and offering expenses. The discount of $2.1 million at issuance will be accreted as additional interest over the expected term on the Notes. On February 15, 2013, the Partnership used the net proceeds from the offering, after paying fees and offering expenses, together with a portion of the $115.0 million term loan to finance its acquisition of all of the outstanding membership interests in Cascade Kelly and to pay related transaction costs.

The Notes were issued pursuant to an indenture dated as of February 14, 2013 (the “Indenture”) among the Partnership, our subsidiary guarantors and FS Energy. The Notes will mature on February 14, 2018. Interest on the Notes accrued from February 14, 2013 and will be paid semi-annually on February 14 and August 14 of each year, beginning on August 14, 2013.

The Partnership may redeem all or some of the Notes at any time or from time to time pursuant to the terms of the Indenture. The Notes are also subject to optional or mandatory exchange for HY Bonds (as such term is defined in the Indenture) at the time and on the terms specified in the Indenture. The holders of the Notes may require the Partnership to repurchase the 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 Notes are guaranteed on a senior, unsecured basis by certain of the Partnership’s wholly owned subsidiaries. The Indenture contains covenants that are no more restrictive to the Partnership in the aggregate than the terms, conditions, covenants and defaults contained in its Credit Agreement and will limit the Partnership’s ability to, among other things, incur additional indebtedness, make distributions to equity owners, make certain investments, restrict distributions by its subsidiaries, create liens, enter into sale-leaseback transactions, sell assets or merge with other entities.

Deferred Financing Fees

The Partnership incurs bank fees related to its Credit Agreement. These deferred financing fees are amortized over the life of the Credit Agreement. The Partnership did not capitalize deferred financing fees for the three months ended June 30, 2013 and 2012. The Partnership capitalized deferred financing fees of $5.1 million and $1.1 million for the six months ended June 30, 2013 and 2012, respectively. Amortization expenses of approximately $1.7 million and $1.4 million for the three months ended June 30, 2013 and 2012, respectively, and $3.3 million and $2.7 million for the six months ended June 30, 2013 and 2012, respectively, are included in selling, general and administrative expenses in the accompanying consolidated statements of income. Unamortized fees are included in other current assets and other long-term assets.

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Note 7. Related Party Transactions

The Partnership is a party to a Second Amended and Restated Terminal Storage Rental and Throughput Agreement, as amended, with Global Petroleum Corp. (“GPC”), an affiliate of the Partnership that is 100% owned by members of the Slifka family. The agreement, which extends through July 31, 2015, is accounted for as an operating lease. After July 31, 2015, the agreement continues for successive one year terms unless either party gives notice to terminate at least 90 days prior to the expiration of the then current term. The expenses under this agreement totaled approximately $2.2 million and $2.2 million for the three months ended June 30, 2013 and 2012, respectively, and $4.5 million and $4.4 million for the six months ended June 30, 2013 and 2012, 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, 2013 and 2012 and $48,000 for each of the six months ended June 30, 2013 and 2012. These charges were recorded in selling, general and administrative expenses in the accompanying consolidated statements of income. On March 9, 2012, in connection with the Partnership’s acquisition of Alliance (see Note 2), 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, 2013, no such notice of termination was given by either party.

Prior to the acquisition of Alliance on March 1, 2012, the Partnership was a party to an Amended and Restated Services Agreement with Alliance. Pursuant to the agreement, the Partnership provided certain administrative, accounting and information processing services, and the use of certain facilities, to Alliance. The income from these services was approximately $31,000 for the six months ended June 30, 2012. These fees were recorded as an offset to selling, general and administrative expenses in the accompanying consolidated statements of income. On March 9, 2012, in connection with the acquisition of Alliance, the agreement was terminated without penalty. There were no settlement gains or losses recognized as a result of the termination of this agreement.

In addition, on March 9, 2012, following the closing of the acquisition of Alliance, Global Companies and AE Holdings entered into a shared services agreement pursuant to which Global Companies provides AE Holdings with certain tax, accounting, treasury and legal support services for which AE Holdings pays Global Companies $15,000 per year. The shared services agreement is for an indefinite term and AE Holdings may terminate its receipt of some or all of the services upon 180 days’ notice. As of June 30, 2013, no such notice of termination was given by AE Holdings.

Prior to the acquisition of Alliance on March 1, 2012, the Partnership sold refined petroleum products and renewable fuels to Alliance at prevailing market prices at the time of delivery. Sales to Alliance were approximately $40.6 million for the six months ended June 30, 2012.

In addition, Global Companies and GMG entered into management agreements with Alliance in connection with the Partnership’s September 2010 acquisition of retail gasoline stations from ExxonMobil. The management fee and overhead reimbursement were approximately $433,000 and $250,000, respectively, for the six months ended June 30, 2012. On March 9, 2012, in connection with the acquisition of Alliance, the management agreements were terminated without penalty.

The General Partner employs all of the Partnership’s employees, except for its gasoline station and convenience store employees and certain union personnel, who are employed by GMG. The Partnership reimburses the General Partner for expenses incurred in connection with these employees. These expenses, including payroll, payroll taxes and bonus accruals, were $17.3 million and $10.4 million for the three months ended June 30, 2013 and 2012, respectively, and $31.1 million and $20.1 million for the six months ended June 30, 2013 and 2012, 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.

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Note 7. Related Party Transactions (continued)

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

	June 30,		December 31,
	2013		2012
Receivables from GPC	$	433	$	275
Receivables from the General Partner (1)	967		1,032
Total	$	1,400	$	1,307

(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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Note 8. Cash Distributions (continued)

The Partnership paid the following cash distribution during 2013 (in thousands, except per unit data):

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

02/14/13 (1)	$	0.5700	$	15,636	$	131	$	579	$	16,346
05/15/13 (2)	0.5825		15,979		134		683		16,796

(1) This distribution of $0.57 per unit resulted in the Partnership exceeding its second target level distribution for the fourth quarter of 2012. As a result, the General Partner, as the holder of the IDRs, received an incentive distribution.

(2) This distribution of $0.5825 per unit resulted in the Partnership exceeding its second target level distribution for the first quarter of 2013. As a result, the General Partner, as the holder of the IDRs, received an incentive distribution.

In addition, on July 23, 2013, the board of directors of the General Partner declared a quarterly cash distribution of $0.5875 per unit ($2.35 per unit on an annualized basis) for the period from April 1, 2013 through June 30, 2013. On August 14, 2013, the Partnership will pay this cash distribution to its common unitholders of record as of the close of business August 5, 2013. This distribution will result in the Partnership exceeding its second target level distribution for the quarter ended June 30, 2013.

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 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, 2013 and 2012, 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, 2012.

In the Wholesale reporting segment, the Partnership sells unbranded gasoline (including gasoline blendstocks such as ethanol and naphtha) and diesel to unbranded gasoline customers and other resellers of transportation fuels. The Partnership sells home heating oil, diesel, kerosene, residual oil and propane to home heating oil retailers and wholesale distributors. The Partnership also sells and transports crude oil to refiners. Generally, customers use their own vehicles or contract carriers to take delivery of the gasoline and distillate products at bulk terminals and inland storage facilities that the Partnership owns or controls or with which it has throughput or exchange arrangements. Crude oil is aggregated by truck or pipeline in the mid-continent, transported on land by train and shipped to refineries on the East Coast and West Coast in barges. Additionally, ethanol is shipped primarily by rail 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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Note 9. Segment Reporting (continued)

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

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

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

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

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Note 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,
	2013			2012			2013			2012
Wholesale Segment:
Sales
Gasoline and gasoline blendstocks	$	1,959,686		$	2,043,385		$	4,161,155		$	3,895,370
Other oils and related products (1)	1,709,322			836,794			4,025,841			2,265,117
Total	$	3,669,008		$	2,880,179		$	8,186,996		$	6,160,487
Net product margin
Gasoline and gasoline blendstocks	$	16,043		$	6,718		$	25,656		$	25,457
Other oils and related products (1)	30,102			28,002			71,669			42,455
Total	$	46,145		$	34,720		$	97,325		$	67,912
Gasoline Distribution and Station Operations Segment:
Sales
Gasoline	$	833,121		$	807,108		$	1,578,711		$	1,273,585
Station operations (2)	37,313			35,405			68,921			55,046
Total	$	870,434		$	842,513		$	1,647,632		$	1,328,631
Net product margin
Gasoline	$	38,897		$	43,525		$	67,090		$	55,728
Station operations (2)	19,939			18,734			37,775			29,694
Total	$	58,836		$	62,259		$	104,865		$	85,422
Commercial Segment:
Sales	$	232,314		$	193,371		$	526,318		$	402,426
Net product margin	$	6,170		$	3,179		$	16,595		$	9,379
Combined sales and net product margin:
Sales	$	4,771,756		$	3,916,063		$	10,360,946		$	7,891,544
Net product margin (3)	$	111,151		$	100,158		$	218,785		$	162,713
Depreciation allocated to cost of sales	(13,294		)	(9,483		)	(25,076		)	(16,719		)
Combined gross profit	$	97,857		$	90,675		$	193,709		$	145,994

(1) Other oils and related products primarily consist of distillates, residual oil and crude oil and include the February 2013 acquisitions of Basin Transload and Cascade Kelly (see Note 2).

(2) 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.

(3) Net 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 net product margin on a combined basis to gross profit, a directly comparable GAAP measure.

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Note 9. Segment Reporting (continued)

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
Combined gross profit	$	97,857		$	90,675		$	193,709		$	145,994
Operating costs and expenses not allocated to operating segments:
Selling, general and administrative expenses	27,077			24,036			53,837			46,503
Operating expenses	47,367			37,138			90,707			60,496
Amortization expense	5,677			2,288			10,053			3,862
Total operating costs and expenses	80,121			63,462			154,597			110,861
Operating income	17,736			27,213			39,112			35,133
Interest expense	(9,024		)	(9,148		)	(17,940		)	(18,468		)
Income tax benefit	—			450			1,875			450
Net income	8,712			18,515			23,047			17,115
Net loss attributable to noncontrolling interest	(18		)	—			472			—
Net income attributable to Global Partners LP	$	8,694		$	18,515		$	23,519		$	17,115

There were no foreign sales for the three and six months ended June 30, 2013 and 2012. 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 $229.5 million, of which approximately $73.1 million of property and equipment has primarily been allocated to the Wholesale segment as of the respective acquisition dates. As of June 30, 2013, these assets had a combined net book value of approximately $69.2 million.

In connection with its acquisitions of retail gasoline stations from Alliance in March 2012 and ExxonMobil in September 2010, the Partnership acquired assets of approximately $627.6 million, including goodwill, of which approximately $465.8 million of property and equipment has been allocated to the Gasoline Distribution and Station Operations segment as of the respective acquisition date. As of June 30, 2013, these assets had a collective net book value of approximately $453.0 million.

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

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(Unaudited)

Note 10. Property and Equipment

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

	June 30,			December 31,
	2013			2012
Buildings and improvements	$	591,601		$	498,984
Land	288,829			289,903
Fixtures and equipment	23,729			14,554
Construction in process	23,987			17,809
Capitalized internal use software	—			5,847
Total property and equipment	928,146			827,097
Less accumulated depreciation	(140,429		)	(114,775		)
Total	$	787,717		$	712,322

The increase of approximately $101.0 million in total property and equipment at June 30, 2013 was primarily due to the Partnership’s acquisitions of its membership interest in Basin Transload and Cascade Kelly (see Note 2).

Note 11. Environmental Liabilities and Asset Retirement Obligations

Environmental Liabilities

The Partnership currently 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 Company, 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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(Unaudited)

Note 11. Environmental Liabilities and Asset Retirement Obligations (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. In June 2008, the Partnership submitted a remedial action work plan to NYDEC, implementing NYDEC’s conditional approval of the remedial action plan submitted by ExxonMobil. The Partnership responded to NYDEC’s requests for additional information and conducted pilot tests for the remediation outlined in the work plan. Based on the results of such pilot tests, the Partnership changed its estimate and reduced the environmental liability by $2.8 million during the fourth quarter ended December 31, 2008. In July 2009, NYDEC approved the remedial action work plan, and the Partnership signed a Stipulation Agreement with NYDEC to govern implementation of the approved plan. The remedial action work has been implemented pursuant to the approved work plan, and the post-remediation stage of operation, monitoring and maintenance has commenced and is ongoing. As a result, the Partnership changed its estimate and reduced the environmental liability by $1.7 million during the second quarter ended June 30, 2011.

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(Unaudited)

Note 11. Environmental Liabilities and Asset Retirement Obligations (continued)

The following table presents a summary roll forward of the Partnership’s environmental liabilities at June 30, 2013 (in thousands):

	Balance at										Balance at
	December 31,		Payments in			Dispositions			Other		June 30,
Environmental Liability Related to:	2012		2013			2013			Adjustments		2013
ExxonMobil Gasoline Stations	$	26,610	$	(888	)	$	(266	)	$	479	$	25,935
Alliance Gasoline Stations	14,984		(410		)	(600		)	235		14,209
Mutual Oil	625		—			—			—		625
Newburgh	1,500		—			—			—		1,500
Glenwood Landing and Inwood	347		(18		)	—			—		329
Albany	106		(38		)	—			—		68
Total environmental liabilities	$	44,172	$	(1,354	)	$	(866	)	$	714	$	42,666

Current portion	$	4,341									$	4,286
Long-term portion	39,831										38,380
Total environmental liabilities	$	44,172									$	42,666

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

Asset Retirement Obligations

The Partnership is required to account for the legal obligations associated with the long-lived assets that result from the acquisition, construction, development or operation of long-lived assets. Such asset retirement obligations specifically pertain to the treatment of underground gasoline storage tanks (“USTs”) that exist in those U.S. states which statutorily require removal of the USTs at a certain point in time. Specifically, the Partnership’s retirement obligations consist of the estimated costs of removal and disposals of USTs in specific states. The fair value of a liability for an asset retirement obligation is recognized in the year in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying cost of the asset. The Partnership has recorded approximately $1.9 million in total asset retirement obligations which are included in other long-term liabilities in the accompanying balance sheet at June 30, 2013.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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, unit awards and substitute awards.

Phantom Unit Awards

On June 27, 2013, the Compensation Committee of the board of directors of the General Partner granted a total of 510,836 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: 33 1/3% on July 1, 2017, 66 2/3% 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: 33 1/3% on December 31, 2014, 66 2/3% 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: 33 1/3% on December 31, 2014, 66 2/3% 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. Compensation expense was immaterial for the quarter ended June 30, 2013.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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, 2013 and December 31, 2012 (in thousands):

	Fair Value as of June 30, 2013												Fair Value as of December 31, 2012
	Total			Level 1			Level 2			Level 3			Total			Level 1			Level 2			Level 3
Assets:
Hedged inventories	$	217,356		$	—		$	217,356		$	—		$	526,107		$	—		$	526,107		$	—
Fair value of forward fixed price contracts	2,022			—			2,022			—			48,062			—			48,062			—
Swap agreements and options	129			126			3			—			179			54			125			—
Foreign currency derivatives	380			—			380			—			145			—			145			—
Interest rate cap	92			—			92			—			35			—			35			—
Broker margin deposits	21,954			21,954			—			—			54,726			54,726			—			—
Pension plan	17,430			17,430			—			—			17,158			17,158			—			—
Total	$	259,363		$	39,510		$	219,853		$	—		$	646,412		$	71,938		$	574,474		$	—

Liabilities:
Obligations on forward fixed price contracts	$	(8,730	)	$	—		$	(1,055	)	$	(7,675	)	$	(34,474	)	$	—		$	(34,474	)	$	—
Swap agreements and option contracts	(126		)	(126		)	—			—			(54		)	(54		)	—			—
Interest rate collar and swap	(9,937		)	—			(9,937		)	—			(13,402		)	—			(13,402		)	—
Total liabilities	$	(18,793	)	$	(126	)	$	(10,992	)	$	(7,675	)	$	(47,930	)	$	(54	)	$	(47,876	)	$	—

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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 collar, interest rate swap and interest rate cap. The fair value of the foreign currency derivatives is 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, 2013.

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.

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, 2013 (in thousands):

	Liabilities
Fair value at December 31, 2012	$	—
Reclass of Level 2 inputs	15,127
Change in fair value recorded in Cost of Sales	(22,802		)
Fair value at June 30, 2013	$	(7,675	)

The fair values of the Partnership’s pension plan assets at June 30, 2013 and December 31, 2012 were determined by Level 1 inputs which principally consist of quoted prices in active markets for identical assets. The plan assets primarily consisted of fixed income securities, equity securities and cash and cash equivalents.

For assets and liabilities measured on a non-recurring basis during the period, accounting guidance requires quantitative disclosures about the fair value measurements separately for each major category. See Note 2 for acquired assets and liabilities measured on a non-recurring basis during the fiscal quarters ended June 30, 2013 and 2012.

Financial Instruments

The fair value of the Partnership’s financial instruments approximated the carrying value as of June 30, 2013 and December 31, 2012, 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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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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. 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 satisfy the “more likely than not” recognition criteria in accordance with the FASB’s guidance regarding income taxes. Based upon projections of future taxable income, the Partnership believes that the recorded deferred tax assets will be realized.

Note 15. Legal Proceedings

General

Although the Partnership may, from time to time, be involved in litigation and claims arising out of its operations in the normal course of business, the Partnership does not believe that it is a party to any litigation that will have a material adverse impact on its financial condition or results of operations. Except as described below and in Note 11 included herein, the Partnership is not aware of any significant legal or governmental proceedings against it, or contemplated to be brought against it. The Partnership maintains insurance policies with insurers in amounts and with coverage and deductibles as its general partner believes are reasonable and prudent. However, the Partnership can provide no assurance that this insurance will be adequate to protect it from all material expenses related to potential future claims or that these levels of insurance will be available in the future at economically acceptable prices.

Other

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 16. Accumulated Other Comprehensive Loss

The following table presents the changes in accumulated other comprehensive loss for the three and six months ended June 30, 2013 (in thousands):

Three Months Ended June 30, 2013	Pension Plan			Derivatives			Total
Balance at March 31, 2013	$	(4,118	)	$	(13,313	)	$	(17,431	)
Other comprehensive income (loss) before reclassifications of gain (loss)	1,259			2,049			3,308
Amount of gain (loss) reclassified from accumulated other comprehensive income	—			—			—
Total comprehensive income	1,259			2,049			3,308
Balance at June 30, 2013	$	(2,859	)	$	(11,264	)	$	(14,123	)

Six Months Ended June 30, 2013	Pension Plan			Derivatives			Total
Balance at December 31, 2012	$	(4,884	)	$	(14,786	)	$	(19,670	)
Other comprehensive income before reclassifications of gain (loss)	2,025			3,522			5,547
Amount of gain (loss) reclassified from accumulated other comprehensive income	—			—			—
Total comprehensive income	2,025			3,522			5,547
Balance at June 30, 2013	$	(2,859	)	$	(11,264	)	$	(14,123	)

Note 17. Non-Cash Investing Activities

The following table presents non-cash investing activities for the six months ended June 30, 2012 (in thousands):

Effect of acquisition of Alliance Energy LLC:
Fair value of tangible assets acquired	$	(334,536	)
Fair value of liabilities assumed	76,784
Fair value of acquired intangible assets	(35,000		)
Fair value of common units issued	130,513
Consideration paid in excess of fair value (goodwill)	(19,659		)
Net cash paid in connection with the acquisition of Alliance	$	(181,898	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 18. New Accounting Standards

Accounting Standards or Updates Recently Adopted

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

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

In July 2012, the FASB issued ASU No. 2012-02, “Intangibles—Goodwill and Other (Topic 350): Testing Indefinite-Lived Intangible Assets for Impairment.” This standard simplifies the impairment test for indefinite-lived intangible assets other than goodwill by giving entities the option to first assess qualitative factors to determine whether it is more likely than not that an indefinite-lived intangible asset is impaired. The results of the qualitative assessment would be used as a basis in determining whether it is necessary to perform the two-step quantitative impairment testing. An entity can choose to perform the qualitative assessment on none, some or all of its indefinite-lived intangible assets, or may bypass the qualitative assessment and proceed directly to the quantitative impairment test. The Partnership adopted this guidance on January 1, 2013 which did not have a material impact on the Partnership’s financial position, results of operations or cash flows.

Accounting Standards or Updates Not Yet Effective

The Partnership has evaluated the accounting guidance recently issued and as determined that these standards or updates will not have a material impact on its financial position, results of operations or cash flows.

Note 19. Subsequent Event

On July 23, 2013, the board of directors of the General Partner declared a quarterly cash distribution of $0.5875 per unit ($2.35 per unit on an annualized basis) for the period from April 1, 2013 through June 30, 2013. On August 14, 2013, the Partnership will pay this cash distribution to its common unitholders of record as of the close of business August 5, 2013.

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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, 2012, 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 station and convenience store business could expose us to an increase in consumer litigation and result in an unfavorable outcome or settlement of one or more lawsuits where insurance proceeds are insufficient or otherwise unavailable.

· Our 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.

· 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.

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

· Our business could be affected by a range of issues, such as dramatic changes in commodity prices, energy conservation, competition, the global economic climate, movement of products between foreign locales and the United States, weekly and monthly refinery output levels, changes in local, domestic and worldwide inventory levels, 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.

· 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, 2012 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. 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. We are one of the largest distributors of gasoline (including gasoline blendstocks such as ethanol and naphtha), distillates (such as home heating oil, diesel and kerosene), residual oil and renewable fuels to wholesalers, retailers and commercial customers in the New England states and New York. We also engage in the purchasing, selling and logistics of transporting domestic and Canadian crude oil and other products via rail, establishing a “virtual pipeline” from the mid-continent region of the United States and Canada to the East and West Coasts for distribution to refiners and other customers. We own, control or have access to one of the largest terminal networks of refined petroleum products and renewable fuels in Massachusetts, Maine, Connecticut, Vermont, New Hampshire, Rhode Island, New York, New Jersey and Pennsylvania (collectively, the “Northeast”). We also own and control terminals in North Dakota and Oregon that extend our origin-to-destination capabilities. We are a major multi-brand gasoline distributor and have a portfolio of approximately 900 owned, leased and/or supplied gasoline stations primarily in the Northeast. We are also a distributor of natural gas and propane. In addition, we provide ancillary services to companies and receive revenue from these ancillary services and from retail sales of gasoline, convenience store sales and gasoline station rental income.

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

Collectively, we sold approximately $4.7 billion and $10.3 billion of refined petroleum products, renewable fuels, crude oil, natural gas and propane for the three and six months ended June 30, 2013, respectively. In addition, we had other revenues of approximately $37.3 million and $68.9 million for the three and six months ended June 30, 2013, 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

We engage in the logistics of gathering, storage, transportation and marketing of refined petroleum products, renewable fuels, crude oil and propane. In February 2013, we acquired a 60% membership interest in Basin Transload, which operates two transloading facilities in Columbus and Beulah, North Dakota for crude oil and other products, and 100% of the membership interest in Cascade Kelly, which owns a West Coast crude oil and ethanol 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 of North Dakota to Phillips 66’s Bayway, New Jersey refinery.

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

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

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Gasoline Distribution and Station Operations

As of June 30, 2013, we had a portfolio of approximately 900 owned, leased and/or supplied gasoline stations primarily in the Northeast. In September 2010, we completed the acquisition from ExxonMobil Corporation of 190 retail gasoline stations, together with the rights to (i) supply Mobil-branded fuel to those stations as well as an additional 31 existing locations in Massachusetts, New 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. which is approximately 95% owned by members of the Slifka family.

On April 26, 2012, we entered into an agreement with Getty Realty Corp. (“Getty Realty”) to supply and provide management services to more than 200 of its gasoline stations in New York and New Jersey. On November 19, 2012, we signed a long-term lease agreement with Getty Realty for approximately 90 of those 200 sites, which enables us to supply gasoline to and operate gasoline stations in the New York City boroughs of Queens, Manhattan and the Bronx as well as in Long Island and Westchester County. The lease with Getty Realty significantly expands our retail gasoline and fuel distribution presence in the New York metro region.

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

Commercial

This segment includes sales and deliveries to end user customers in the public sector and to large commercial and industrial end users of unbranded gasoline, home heating oil, diesel, kerosene, residual oil, renewable fuels and natural gas. In the case of commercial and industrial end user customers, we sell our products primarily either through a competitive bidding process or through contracts of various terms. Our Commercial segment also includes sales of custom blended distillates and residual oil delivered by barge or from a terminal dock to ships through bunkering activity. For the three and six months ended June 30, 2013 and 2012, the Commercial operating segment did not meet the quantitative metrics for disclosure as a reportable segment on a stand-alone basis. However, we have elected to present segment disclosures for the Commercial operating segment as we believe such disclosures are meaningful to the user of our financial information.

Products and Operational Structure

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

Due to the nature of our business and our customers’ 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

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

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

Outlook

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

· Our business is influenced by the overall forward market for refined petroleum products, renewable fuels and crude oil, and increases and/or decreases in the prices of these products may adversely impact our financial condition, results of operations and cash available for distribution to our unitholders and the amount of borrowing available for working capital under our credit agreement. Results from our purchasing, storing, terminalling, transporting and selling operations are influenced by prices for these products, 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 retail market price. 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. Consistent with our business strategy, 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 make such accretive acquisitions for a number of reasons, including, but not limited to, the following: (1) we are unable to identify attractive transaction candidates or negotiate acceptable transaction contracts; (2) we are unable to raise 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 would be limited. We can give no assurance that our transaction efforts will be successful or that any such transaction 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 rail and marine transportation services that could affect the flow of service. In addition, labor disputes between the railroads and their union employees and labor renegotiations or a work stoppage at railroads could also disrupt rail service. These events could result in service disruptions and increased cost which could also adversely affect our financial condition, results of operations and cash available for distribution to our unitholders. Other disruptions, such as those due to an act of terrorism or war, could also adversely affect our business.

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

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

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· New, stricter environmental laws and regulations could significantly increase our costs, which could adversely affect our results of operations and financial condition. Our operations are subject to federal, state and local laws and regulations regulating 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) net 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.

Net Product Margin

We view net product margin as an important performance measure of the core profitability of our operations. We review net product margin monthly for consistency and trend analysis. We define net product margin as our sales minus product costs. 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 and gasoline station rental income. 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. We also look at net product margin on a per unit basis (net product margin divided by volume). Net product margin is a non-GAAP financial measure used by management and external users of our consolidated financial statements to assess our business. Net 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 net product margin may not be comparable to net product margin or a similarly titled measure of other companies.

Gross Profit

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

EBITDA

EBITDA is a non-GAAP financial measure used as a supplemental financial measure by management and external users of our consolidated financial statements, such as investors, commercial banks and research analysts, to assess:

· our compliance with certain financial covenants included in our debt agreements;

· our financial performance without regard to financing methods, capital structure, income taxes or historical cost basis;

· our ability to generate cash sufficient to pay interest on our indebtedness and to make distributions to our partners;

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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 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 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 and gasoline stations used in our business. Lease payments and storage expenses, maintenance and repair, utilities, taxes, labor and labor-related expenses comprise the most significant portion of our operating expenses. These expenses remain relatively stable independent of the volumes through our system but fluctuate slightly depending on the activities performed during a specific period.

Net Income Per Diluted Limited Partner Unit

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

Degree Day

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

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Three and Six Months Ended June 30, 2013 and 2012

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

· For the first six months of 2013, we recognized Alliance’s results for the full period compared to a four-month period in 2012 as we acquired Alliance on March 1, 2012.

· In our Wholesale segment, in part through the February 2013 acquisitions of a 60% membership interest in Basin Transload and a 100% membership interest in Cascade Kelly, we continued our expansion into crude oil logistics, including the gathering, storage, transportation and marketing of crude oil which improved our Wholesale segment net product margin.

· During the first half of 2013, we continued to expand our wholesale gasoline and gasoline blendstocks and distillates businesses by expanding terminal throughput and sales locations at third-party facilities across the country.

· While our net product margin from wholesale gasoline and gasoline blendstocks sales increased for the second quarter of 2013 compared to the same period in 2012, our wholesale gasoline and gasoline blendstocks business was negatively impacted for the first half of 2013 due to tighter margins related to market conditions during the first quarter.

· In our Gasoline Distribution and Station Operations segment, rising gasoline prices typically compress our gasoline net product margins and declining gasoline prices typically improve our gasoline net product margins. Gasoline prices rose for much of the second quarter and most of the first half of 2013 which had a negative impact on our net product margins in our gasoline distribution business.

· Operating expenses increased by $10.2 million and $30.2 million for the three and six months ended June 30, 2013, respectively, compared to the same periods in 2012, primarily due to the February 2013 acquisitions of Basin Transload and Cascade Kelly and the March 2012 acquisition of Alliance.

· Temperatures for the three and six months ended June 30, 2013 were 18% and 21%, respectively, colder than the same periods in 2012 which improved our Wholesale and Commercial net product margins.

· Our net product margins for the three and six months ended June 30, 2013 and 2012 were also affected by a variety of other factors, such as changes in commodity prices, movement of products between foreign locales and within the United States, changes in refiner demand, weekly and monthly refinery output levels, changes in local, domestic and worldwide inventory levels, seasonality, supply, weather and logistics disruptions.

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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,
	2013			2012			2013			2012
Net income attributable to Global Partners LP	$	8,694		$	18,515		$	23,519		$	17,115

Net income per diluted limited partner unit (1)	$	0.29		$	0.66		$	0.80		$	0.65

EBITDA (2)	$	36,973		$	40,790		$	75,743		$	59,240

Distributable cash flow (3)	$	23,397		$	26,679		$	49,971		$	33,747

Wholesale Segment:
Volume (gallons)	1,374,820			1,020,058			2,953,289			2,148,902
Sales
Gasoline and gasoline blendstocks	$	1,959,686		$	2,043,385		$	4,161,155		$	3,895,370
Other oils and related products (4)	1,709,322			836,794			4,025,841			2,265,117
Total	$	3,669,008		$	2,880,179		$	8,186,996		$	6,160,487
Net product margin
Gasoline and gasoline blendstocks	$	16,043		$	6,718		$	25,656		$	25,457
Other oils and related products (4)	30,102			28,002			71,669			42,455
Total	$	46,145		$	34,720		$	97,325		$	67,912
Gasoline Distribution and Station Operations Segment:
Volume (gallons)	264,190			262,664			507,501			403,886
Sales
Gasoline	$	833,121		$	807,108		$	1,578,711		$	1,273,585
Station operations (5)	37,313			35,405			68,921			55,046
Total	$	870,434		$	842,513		$	1,647,632		$	1,328,631
Net product margin
Gasoline	$	38,897		$	43,525		$	67,090		$	55,728
Station operations (5)	19,939			18,734			37,775			29,694
Total	$	58,836		$	62,259		$	104,865		$	85,422
Commercial Segment:
Volume (gallons)	94,305			85,527			208,540			174,644
Sales	$	232,314		$	193,371		$	526,318		$	402,426
Net product margin	$	6,170		$	3,179		$	16,595		$	9,379
Combined sales and net product margin:
Sales	$	4,771,756		$	3,916,063		$	10,360,946		$	7,891,544
Net product margin (6)	$	111,151		$	100,158		$	218,785		$	162,713
Depreciation allocated to cost of sales	(13,294		)	(9,483		)	(25,076		)	(16,719		)
Combined gross profit	$	97,857		$	90,675		$	193,709		$	145,994

Weather conditions:
Normal heating degree days	784			784			3,654			3,685
Actual heating degree days	721			611			3,532			2,924
Variance from normal heating degree days	(8%		)	(22%		)	(3%		)	(21%		)
Variance from prior period actual heating degree days	18%			(17%		)	21%			(20%		)

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

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

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

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(4) Other oils and related products primarily consist of distillates, residual oil and crude oil and include the February 2013 acquisitions of Basin Transload and Cascade Kelly (see Note 2 of Notes to Consolidated Financial Statements).

(5) 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.

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

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
Reconciliation of net income to EBITDA:
Net income	$	8,712		$	18,515		$	23,047		$	17,115
Net (income) loss attributable to noncontrolling interest	(18		)	—			472			—
Net income attributable to Global Partners LP	8,694			18,515			23,519			17,115
Depreciation and amortization and amortization of deferred financing fees, excluding the impact of noncontrolling interest	19,255			13,577			36,159			24,107
Interest expense	9,024			9,148			17,940			18,468
Income tax benefit	—			(450		)	(1,875		)	(450		)
EBITDA	$	36,973		$	40,790		$	75,743		$	59,240

Reconciliation of net cash provided by operating activities to EBITDA:
Net cash provided by operating activities	$	44,934		$	258,063		$	327,712		$	216,300
Net changes in operating assets and liabilities and certain non-cash items	(14,928		)	(225,971		)	(265,109		)	(175,078		)
Net cash from operating activities and changes in operating assets and liabilities attributable to noncontrolling interest	(2,057		)	—			(2,925		)	—
Interest expense	9,024			9,148			17,940			18,468
Income tax benefit	—			(450		)	(1,875		)	(450		)
EBITDA	$	36,973		$	40,790		$	75,743		$	59,240

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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,
	2013			2012			2013			2012
Reconciliation of net income to distributable cash flow:
Net income	$	8,712		$	18,515		$	23,047		$	17,115
Net (income) loss attributable to noncontrolling interest	(18		)	—			472			—
Net income attributable to Global Partners LP	8,694			18,515			23,519			17,115
Depreciation and amortization and amortization of deferred financing fees, excluding the impact of noncontrolling interest	19,255			13,577			36,159			24,107
Amortization of senior notes discount	105			—			158			—
Amortization of routine bank refinancing fees	(985		)	(959		)	(1,970		)	(1,918		)
Maintenance capital expenditures	(3,672		)	(4,454		)	(7,895		)	(5,557		)
Distributable cash flow	$	23,397		$	26,679		$	49,971		$	33,747

Reconciliation of net cash provided by operating activities to distributable cash flow:
Net cash provided by operating activities	$	44,934		$	258,063		$	327,712		$	216,300
Net changes in operating assets and liabilities and certain non-cash items	(14,928		)	(225,971		)	(265,109		)	(175,078		)
Amortization of senior notes discount	105			—			158			—
Net cash from operating activities and changes in operating assets and liabilities attributable to noncontrolling interest	(2,057		)	—			(2,925		)	—
Amortization of routine bank refinancing fees	(985		)	(959		)	(1,970		)	(1,918		)
Maintenance capital expenditures	(3,672		)	(4,454		)	(7,895		)	(5,557		)
Distributable cash flow	$	23,397		$	26,679		$	49,971		$	33,747

Consolidated Results

Our total sales for the three months ended June 30, 2013 increased by $0.9 billion, or 22%, to $4.8 billion compared to $3.9 billion for the same period in 2012, primarily due to an increase in volume sold. Our aggregate volume of product sold was approximately 1.7 billion gallons for the second quarter of 2013 compared to 1.3 billion gallons for the same period in 2012, an increase of 365 million gallons, or 27%. The increase in volume sold includes increases of 355 million gallons in our wholesale business, due to increases in our crude oil activities, gasoline and gasoline blendstocks and, due to colder weather period over period, distillates. The number of actual heating degree days increased 18% to 721 for the second quarter of 2013 compared to 611 for the same period in 2012. The increase in total volume also includes increases of 9 million gallons in our commercial business due largely to an increase in bunkering activity and to colder weather period over period and 1 million gallons in our gasoline distribution business. Our gross profit for the second quarter of 2013 was $97.9 million, an increase of $7.2 million, or 8%, compared to $90.7 million for the second quarter of 2012, due primarily to favorable market conditions in gasoline blendstocks, including less backwardation compared to the same period in 2012, and to an increase in crude oil activities, including Phillips 66 transactions and the February 2013 acquisitions of Basin Transload and Cascade Kelly. The increase in gross profit was partially offset by a decrease in our gasoline distribution business due to rising gasoline prices during much of the second quarter and by less favorable market conditions in distillates. The increase in gross profit was offset by an increase in depreciation on our North Dakota and Oregon assets, which is included in cost of sales.

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Our total sales for the six months ended June 30, 2013 increased by $2.5 billion, or 31%, to $10.4 billion compared to $7.9 billion for the same period in 2012, primarily due to an increase in volume sold. Our aggregate volume of product sold was 3.7 billion gallons for first half of 2013 compared to 2.7 billion gallons for the same period in 2012, an increase of 942 million gallons, or 35%. The increase in volume sold includes increases of 804 million gallons in our wholesale business, due to increases in our crude oil activities, gasoline and gasoline blendstocks and, due to colder weather period over period, distillates. The number of actual heating degree days increased 21% to 3,532 for the first half of 2013 compared to 2,924 for the same period in 2012. The increase in total volume also includes increases of 104 million gallons in our gasoline distribution business, primarily due to our supply and management agreement and unitary lease with Getty Realty, and 34 million gallons in our commercial business due largely to an increase in bunkering activity and to colder weather period over period. Our gross profit for the first half of 2013 was $193.7 million, an increase of $47.7 million, or 33%, compared to $146.0 million for the same period in 2012, due primarily to the increase in crude oil activities, including Phillips 66 transactions and the February 2013 acquisitions of Basin Transload and Cascade Kelly. Despite the increase, our gross profit was negatively impacted by tighter margins related to market conditions in wholesale gasoline and gasoline blendstocks during the first quarter of 2013, compressed margins in our gasoline distribution business due to rising gasoline prices for most of the first six months of 2013 and less favorable market conditions in distillates. The increase in gross profit was offset by an increase in depreciation on our North Dakota and Oregon assets, which is included in cost of sales.

Wholesale Segment

Gasoline and Gasoline Blendstocks. Sales from wholesale gasoline and gasoline blendstocks were relatively flat at $2.0 billion for the three months ended June 30, 2013 and 2012. Our net product margin from wholesale gasoline and gasoline blendstocks sales for the three months ended June 30, 2013 increased by $9.3 million to $16.0 million from $6.7 million for the same period in 2012 due primarily to favorable market conditions in gasoline blendstocks, including less backwardation compared to the same period in 2012.

During the six months ended June 30, 2013, sales from wholesale gasoline and gasoline blendstocks were $4.2 billion compared to $3.9 billion for the same period in 2012. The increase of $0.3 billion, or 7%, was due primarily to an increase in volume sold which was attributable to an increase in demand for gasoline blendstocks. Our net product margin from wholesale gasoline and gasoline blendstocks sales increased $0.2 million to $25.6 million for the six months ended June 30, 2013 compared to $25.4 million for the same period in 2012.

Other Oils and Related Products. Sales from other oils and related products (primarily distillates, residual oil and crude oil) were $1.7 billion for the three months ended June 30, 2013 compared with $0.8 billion for the same period in 2012. During the six months ended June 30, 2013, sales from other oils and related products were $4.0 billion compared to $2.3 billion for the same period in 2012. The increases of $0.9 million and $1.7 million for the three and six months ended June 30, 2013, respectively, were primarily due to increases in our crude oil activities, including Phillips 66 transactions and the acquisitions of Basin Transload and Cascade Kelly, and in distillates due to colder weather period over period. Primarily for these same reasons, our net product margin increased by $2.1 million, or 7%, to $30.1 million for the second quarter of 2013 compared to $28.0 million for the second quarter of 2012 and by $29.2 million, or 69%, to $71.7 million for the first half of 2013 compared to $42.5 million for the first half of 2012.

Gasoline Distribution and Station Operations Segment

Gasoline Distribution. Sales from gasoline distribution were $833.1 million for the three months ended June 30, 2013 compared with $807.1 million for the same period in 2012. The increase of $26.0 million, or 3%, was due to rising gasoline prices during much of the second quarter of 2013. Our net product margin from gasoline distribution decreased by $4.6 million to $38.9 million for the three months ended June 30, 2013 compared to $43.5 million due to rising gasoline prices during the quarter which compressed our net product margin compared to declining gasoline prices during the second quarter of 2012 which improved our net product margin.

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During the six months ended June 30, 2013, sales from gasoline distribution were $1.6 billion compared to $1.3 billion for the six months ended June 30, 2012. The increase of $305.1 million, or 24%, was due primarily to an increase in volume sold as a result of including Alliance’s results for a full six months compared to four months in 2012 and to our supply and management agreement and unitary lease with Getty Realty which were not in place for the full first half of 2012. Primarily for these same reasons, our net product margin increased by $11.4 million to $67.1 million for the six months ended June 30, 2013 compared to $55.7 million for the same periods in 2012. Despite the increase, our net product margin from gasoline distribution was negatively impacted due to rising gasoline prices during most of the first half of 2013.

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 $37.3 million and $35.4 million for the three months ended June 30, 2013 and 2012, respectively, and $68.9 million and $55.0 million for the six months ended June 30, 2013 and 2012, respectively. Our net product margin from station operations was $19.9 million and $18.7 million for the three months ended June 30, 2013 and 2012, respectively, and $37.8 million and $29.7 million for the six months ended June 30, 2013 and 2012, respectively. The increases in revenues and net product margin for the six months ended June 30, 2013 compared to the same period in 2012 were due primarily to including Alliance’s results for a full six months in 2013 versus four months in 2012.

Commercial Segment

Our commercial sales were $232.3 million and $193.4 million for the three months ended June 30, 2013 and 2012, respectively, and $526.3 million and $402.4 million for the six months ended June 30, 2013 and 2012, respectively. Our commercial net product margins were $6.2 million and $3.2 million for the three months ended June 30, 2013 and 2012, respectively, and $16.6 million and $9.4 million for the six months ended June 30, 2013 and 2012, respectively. The increases of $38.9 million and $3.0 million in sales and net product margin, respectively, for the second quarter of 2013 and $123.9 million and $7.2 million, respectively, for the first half of 2013 were primarily due to an increase in bunkering activity and to colder weather period over period. In our Commercial segment, residual oil accounted for approximately 52% and 45% of our total commercial volume sold for the three months ended June 30, 2013 and 2012, respectively, and 49% and 39% of our total commercial volume sold for the six months ended June 30, 2013 and 2012, respectively. Distillates, gasoline and natural gas accounted for the remainder of the total commercial sales, volume sold and net product margin.

Selling, General and Administrative Expenses

SG&A expenses increased by $3.0 million, or 13%, to $27.0 million for the three months ended June 30, 2013 compared to $24.0 million for the same period in 2012. The increase includes increases of $3.1 million in professional fees and due diligence costs associated with the growth of our business, including the acquisitions of Basin Transload and Cascade Kelly, $1.6 million in overhead expenses, $1.1 million in bank fees primarily related to the increase in our crude oil activities, and $0.9 million in costs related to our Basin Transload and Cascade Kelly facilities. The increase in SG&A expenses was offset by decreases of $2.0 million in accrued incentive compensation, $1.3 million in commissions related to certain gasoline station operators and $0.4 million in other SG&A expenses.

SG&A expenses increased by $7.3 million, or 16%, to $53.8 million for the six months ended June 30, 2013 compared to $46.5 million for the same period in 2012. The increase, includes increases of $4.0 million in professional fees and due diligence costs associated with the growth of our business, including the acquisitions of Basin Transload and Cascade Kelly, $3.4 million in overhead expenses, $2.8 million in bank fees primarily related to the increase in our crude oil activities, $1.3 million in bad debt expense, $1.3 million in costs related to our Basin Transload and Cascade Kelly facilities and $1.3 million in other SG&A expenses. The increase in SG&A expenses for the first half of 2013 includes expenses related to our retail gasoline stations for a full six months in 2013 versus four months in 2012. The increase in SG&A expenses was offset by decreases of $1.3 million in commissions related to certain gasoline station operators and $1.0 million in accrued incentive compensation. In addition, in the first six months of 2012, we had costs related to Alliance that did not recur in 2013, specifically $4.1 million in one-time acquisition costs and $0.4 million in management fees related to management agreements with Alliance that terminated in connection with the acquisition.

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Operating Expenses

Operating expenses increased by $10.2 million, or 28%, to $47.3 million for the three months ended June 30, 2013 compared to $37.1 million for the same period in 2012. The increase in operating expenses includes $4.9 million in costs associated with our crude oil operations, $4.0 million in costs related to the operations of our retail gasoline stations, including expenses associated with management of the Getty Realty locations, and $1.4 million in operating costs associated with our terminals in Albany, New York, Newburgh, New York and South Portland, Maine.

Operating expenses increased by $30.2 million, or 50%, to $90.7 million for the six months ended June 30, 2013 compared to $60.5 million for the same period in 2012. The increase in operating expenses includes $19.3 million in costs related to the operations of our retail gasoline stations for a full six months in 2013 versus four months in 2012, including expenses associated with management of the Getty Realty locations, $7.9 million in costs associated with our crude oil operations, $2.6 million in operating costs associated with our terminals in Albany, New York, Newburgh, New York and South Portland, Maine and $0.4 million in other operating expenses.

Amortization Expense

Amortization expense related to our intangible assets was $5.7 million and $2.3 million for the three months ended June 30, 2013 and 2012, respectively, and $10.1 million and $3.9 million for the six months ended June 30, 2013 and 2012, respectively. The increases of $3.4 million and $6.2 million were primarily due to the intangible assets acquired in the Basin Transload acquisition.

Interest Expense

Interest expense for the three months ended June 30, 2013 and 2012 was $9.0 million and $9.1 million, respectively. Interest expense for the six months ended June 30, 2013 and 2012 was $17.9 million and $18.4 million, respectively. The decreases of $0.1 million and $0.5 million for the three and six months ended June 30, 2013, respectively, were attributed to carrying lower average balances on our working capital revolving credit facility from carrying lower average dollar values of inventories and to a decrease in costs of borrowings in connection with the November 2012 amendment to our credit agreement. The decrease in interest expense was offset by additional borrowings related to our 2013 acquisitions of Basin Transload and Cascade Kelly and our 2012 acquisition of Alliance.

Income Tax Benefit

Income tax benefit was $0 and $0.4 million for the three months ended June 30, 2013 and 2012, respectively, and $1.9 million and $0.4 million for the six months ended June 30, 2013 and 2012, respectively. The income tax benefit is due to the operating results of our wholly owned subsidiary, Global Montello Group Corp., which is a taxable entity for federal and state income tax purposes.

Net Loss Attributable to Noncontrolling Interest

On February 1, 2013, we acquired a 60% membership interest in Basin Transload. The net income of $18,000 and net loss of $0.5 million for the three and six months ended June 30, 2013, respectively, attributable to noncontrolling interest represents Basin Transload’s 40% interest.

Liquidity and Capital Resources

Liquidity

Our primary liquidity needs are to fund our working capital requirements, capital expenditures and distributions and to service our indebtedness. Cash generated from operations and our working capital revolving credit facility provide our primary sources of liquidity. Working capital decreased by $299.5 million to $162.2 million at June 30, 2013 compared to $461.7 million at December 31, 2012, in part due to changes in accounts receivable, inventories and accounts payable and to the addition of the term loan.

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On February 14, 2013, we paid a cash distribution to our common unitholders and our general partner of approximately $16.3 million for the fourth quarter of 2012. On May 15, 2013, we paid a cash distribution to our common unitholders and our general partner of approximately $16.8 million for the first quarter of 2013. On July 23, 2013, the board of directors of our general partner declared a quarterly cash distribution of $0.5835 per unit ($2.35 per unit on an annualized basis) for the period from April 1, 2013 through June 30, 2013 to our common unitholders of record as of the close of business August 5, 2013. We expect to pay the cash distribution of approximately $17.0 million on August 14, 2013.

Contractual Obligations

We have contractual obligations that are required to be settled in cash. The amounts of our contractual obligations at June 30, 2013 were as follows (in thousands):

	Payments due by period
	Total		Less than 1 year		1-3 years		4-5 years		More than 5 years
Revolver loan obligations (1)	$	615,869	$	—	$	615,869	$	—	$	—
Term loan and senior notes obligation (2)	218,174		122,974		11,200		11,200		72,800
Operating lease obligations (3)	295,640		36,113		83,998		65,345		110,184
Capital lease obligations	1,044		107		353		469		116
Other long-term liabilities (4)	225,070		18,215		67,468		65,372		74,015
Total	$	1,355,798	$	177,409	$	778,888	$	142,386	$	257,115

(1) Includes principal and interest on our working capital revolving credit facility and our revolving credit facility at June 30, 2013 and assumes a ratable payment through the expiration date. Our credit agreement has a contractual maturity of May 14, 2015 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 $115.0 million term loan that will mature on January 31, 2014 and on our 8.00% senior notes due 2018.

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

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

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 $7.9 million and $5.5 million in maintenance capital expenditures for the six months ended June 30, 2013 and 2012, 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 $95.2 million and $310.4 million in expansion capital expenditures for the six months ended June 30, 2013 and 2012, respectively. Specifically, 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

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had $22.1 million in expansion capital expenditures which are included in capital expenditures in the accompanying consolidated statements of cash flows. The $22.1 million consists 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.

For the six months ended June 30, 2012, expansion capital expenditures included approximately $296.2 million associated with the purchase of Alliance, a portion of which was funded through equity and a portion was funded with cash. In addition, we had $14.2 million in expansion capital expenditures which are included in capital expenditures in the accompanying consolidated statements of cash flows. The $14.2 million consists of $7.6 million in costs associated with our crude oil activities, $2.6 million in costs associated with the building of a propane storage and distribution facility in Albany, New York, $2.4 million in site expansion and improvements at certain retail gasoline stations, $0.6 million in costs related to information technology, including increases in storage and computing capacity, $0.5 million in costs to acquire land for future development and $0.5 million in other expansion capital expenditures. The $7.6 million in costs associated with our crude oil activities include 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 tank construction at one of our transloading facilities for the storage and handling of crude oil,

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.

Cash Flow

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

	Six Months Ended
	June 30,
	2013			2012
Net cash provided by operating activities	$	327,712		$	216,300
Net cash used in investing activities	$	(212,907	)	$	(201,624	)
Net cash used in financing activities	$	(111,109	)	$	(14,443	)

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 part of our business, fluctuations in petroleum product prices, working capital requirements and general market conditions.

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Net cash provided by operating activities was $327.7 million for the six months ended June 30, 2013 compared to net cash provided by operating activities of $216.3 million for the six months ended June 30, 2012, for a period-over-period increase in cash provided by operating activities of $111.4 million. The primary drivers of the increase include the following:

	Six Months Ended						Period over
	June 30,						Period
	2013			2012			Change
(Increase) decrease in accounts receivable	$	(48,354	)	$	190,344		$	(238,698	)
Decrease in inventories	281,023			171,479			109,544
Increase (decrease) in accounts payable	1,609			(205,314		)	206,923
Decrease (increase) in the change in fair value of forward fixed price contracts	20,296			(3,296		)	23,592

For the six months ended June 30, 2013, excluding the beginning account balances related to Basin Transload and Cascade Kelly as of their respective acquisition dates (see Note 2 of Notes to Consolidated Financial Statements), the increases in accounts receivable and accounts payable were due primarily to 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 funds.

For the six months ended June 30, 2012, excluding the beginning account balances related to Alliance as of its acquisition date, the decreases in accounts receivable and accounts payable reflected the change in activity as we exited the heating season. The decrease in inventories was due to carrying lower levels of inventory. In addition, due to market direction, the contracts supporting our forward fixed price hedge program required margin payments.

Net cash used in investing activities was $212.9 million for the six months ended June 30, 2013 and included $185.3 million related to our 2013 acquisitions ($91.1 million for our 60% membership interest in Basin Transload and $94.2 million for Cascade Kelly), $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. For the six months ended June 30, 2012, net cash used in investing activities was $201.6 million and included $181.9 million in the cash portion related to the acquisition of Alliance, $14.2 million in expansion capital expenditures and $5.5 million in maintenance capital expenditures. See “—Capital Expenditures” for a discussion of our expansion capital expenditures for the six months ended June 30, 2013 and 2012.

Net cash used in financing activities was $111.1 million for the six months ended June 30, 2013 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 the repurchase of common units pursuant to our repurchase program for future satisfaction of our general partner’s obligations, offset by $115.0 million in borrowings under our term loan, $67.9 million in proceeds from our senior notes and $1.4 million in capital contributions from our noncontrolling interest.

For the six months ended June 30, 2012, net cash used in financing activities was $14.4 million and primarily included $179.2 million in payments on our working capital revolving credit facility, $25.0 million in cash distributions to our common unitholders and our general partner and $2.2 million in the repurchase of common units pursuant to our repurchase program for future satisfaction of our general partner’s obligations, offset by $192.0 million in borrowings from our revolving credit facility substantially in connection with the acquisition of Alliance.

Credit Agreement

We entered into an amended and restated credit agreement dated May 14, 2010 (as amended, our “credit agreement”). Total commitments under our credit agreement are $1.615 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. Our credit agreement will mature on May 14, 2015.

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As of June 30, 2013, there were three facilities under our 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;

· a $500.0 million revolving credit facility to be used for acquisitions and general corporate purposes; and

· a $115.0 million term loan that will mature on January 31, 2014.

In addition, our 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 our credit agreement) then exists, an increase to the working capital revolving credit facility, the revolving credit facility or both by up to another $250.0 million, in the aggregate, for a total credit facility of up to $1.865 billion. Any such request for an increase by us must be in a minimum amount of $5.0 million. We cannot provide assurance, however, that our lending group will agree to fund any request by us for additional amounts in excess of the total available commitments of $1.615 billion.

In addition, our 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 an aggregate amount equal to the lesser of (a) $35.0 million and (b) the Aggregate WC Commitments (as defined in our credit agreement). Swing line loans will bear interest at the Base Rate (as defined in our 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 $1.615 billion.

Pursuant to our credit agreement, and in connection with any agreement by and between a Loan Party and a Lender (as such terms are defined in our 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 our 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 our 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 our 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 our 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 our credit agreement).

Availability under our 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 our credit agreement, our borrowings under the working capital revolving credit facility cannot exceed the then current borrowing base. Availability under our 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 November 16, 2012, borrowings under the working capital revolving credit facility bear 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 our credit agreement). From January 1, 2012 through November 15, 2012, borrowings under the working capital revolving credit facility bore interest at (1) the Eurodollar rate plus 2.50% to 3.00%, (2) the cost of funds rate plus 2.50% to 3.00%, or (3) the base rate plus 1.50% to 2.00%, each depending on the pricing level provided in our credit agreement, which in turn depended upon the Utilization Amount (as defined in our credit agreement).

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plus 3.00% to 3.875%, (2) the cost of funds rate plus 3.00% to 3.875%, or (3) the base rate plus 2.00% to 2.875%, each depending on the pricing level provided in our credit agreement, which in turn depended upon the Combined Total Leverage Ratio (as defined in our credit agreement).

Borrowings under the term loan bear interest at either the Eurodollar rate or the cost of funds rate, in each case plus 3.50%, or the base rate plus 2.50%.

The average interest rate for our credit agreement were 4.5% and 4.1% for the three months ended June 30, 2013 and 2012, respectively, and 4.3% and 4.1% for the six months ended June 30, 2013 and 2012, respectively.

We incur a letter of credit fee of 2.00% - 2.50% per annum for each letter of credit issued. In addition, we incur a commitment fee on the unused portion of each facility under our credit agreement, ranging from 0.375% to 0.50% per annum.

As of June 30, 2013, we had total borrowings outstanding under our credit agreement of $701.2 million, including $374.7 million outstanding on our revolving credit facility and $115.0 million outstanding on the term loan which was used to acquire a 60% membership interest in Basin Transload and a portion of all of the outstanding membership interests in Cascade Kelly. In addition, we had outstanding letters of credit of $301.9 million. Subject to borrowing base limitations, the total remaining availability for borrowings and letters of credit was $611.9 million and $218.9 million at June 30, 2013 and December 31, 2012, respectively.

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

Our obligations under our credit agreement are secured by substantially all of our assets and the assets of our operating company and operating subsidiaries.

Senior Notes

On February 14, 2013, we entered into a Note Purchase Agreement (the “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 of unsecured 8.00% Senior Notes due 2018 (the “Notes”). The Notes were issued in a private placement exempt from registration under the Securities Act of 1933, as amended (the “Securities Act”) and have not been registered under the Securities Act or any state securities laws, and may not be offered or sold except pursuant to an exemption from the registration requirements of the Securities Act and applicable state laws.

Closing of the offering occurred on February 14, 2013. The Notes were sold to FS Energy at 97% of their face amount, resulting in net proceeds to us of approximately $67.9 million. Additionally, we separately paid fees and offering expenses. The discount of $2.1 million at issuance will be accreted as additional interest over the expected term on the Notes. On February 15, 2013, we used the net proceeds from the offering, after paying fees and offering expenses, together with a portion of the $115.0 million term loan to finance our acquisition of all of the outstanding membership interests in Cascade Kelly and to pay related transaction costs.

The Notes were issued pursuant to an indenture dated as of February 14, 2013 (the “Indenture”) among us, our subsidiary guarantors and FS Energy. The Notes will mature on February 14, 2018. Interest on the Notes accrued from February 14, 2013 and will be paid semi-annually on February 14 and August 14 of each year, beginning on August 14, 2013.

We may redeem all or some of the Notes at any time or from time to time pursuant to the terms of the Indenture. The Notes are also subject to optional or mandatory exchange for HY Bonds (as such term is defined in the Indenture) at the time and on the terms specified in the Indenture. The holders of the Notes may require us to repurchase the 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.

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

Deferred Financing Fees

We incur bank fees related to our credit agreement. These deferred financing fees are amortized over the life of our credit agreement. We did not capitalize deferred financing fees for the three months ended June 30, 2013 and 2012. We capitalized deferred financing fees of $5.1 million and $1.1 million for the six months ended June 30, 2013 and 2012, respectively. Amortization expense of approximately $1.7 million and $1.4 million for the three months ended June 30, 2013 and 2012, respectively, and $3.3 million and $2.7 million for the six months ended June 30, 2013 and 2012, respectively, are included in selling, general and administrative expenses in the accompanying consolidated statements of income. Unamortized fees are included in other current assets and other long-term assets.

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements.

Critical Accounting Policies and Estimates

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

These estimates are based on our knowledge and understanding of current conditions and actions that we may take in the future. Changes in these estimates will occur as a result of the passage of time and the occurrence of future events. Subsequent changes in these estimates may have a significant impact on our financial condition and results of operations and are recorded in the period in which they become known. We have identified the following estimates that, in our opinion, are subjective in nature, require the exercise of judgment, and involve complex analysis: inventory, leases, revenue recognition, derivative financial instruments, valuation of intangibles and other long-lived assets, goodwill, environmental and other liabilities and related party transactions.

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, 2012. 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 18 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 utilize an interest rate collar, an interest rate swap 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, 2013, we had total borrowings outstanding under our credit agreement of $701.2 million. Please read Item 2, “Management’s Discussion and Analysis—Liquidity and Capital Resources——Credit Agreement” for information on interest rates related to our borrowings. The impact of a 1% increase in the interest rate on this amount of debt would have resulted in an increase in interest expense, and a corresponding decrease in our results of operations, of approximately $7.0 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 expires on October 2, 2013, is 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.

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 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.

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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, 2013, the fair value of all of our commodity risk derivative instruments and the change in fair value that would be expected from a 10% price increase or decrease are shown in the table below (in thousands):

	Fair Value at			Gain (Loss)
	June 30, 2013			Effect of 10% Price Increase			Effect of 10% Price Decrease
Futures contracts	$	24,697		$	(16,307	)	$	16,307
Swaps, options and other, net	(380		)	(4,707		)	6,289
	$	24,317		$	(21,014	)	$	22,596

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, 2013. For positions where independent quotations are not available, an estimate is provided, or the prevailing market price at which the positions could be liquidated is used. All hedge positions offset physical exposures to the physical market; none of these offsetting physical exposures are included in the above table. Price-risk sensitivities were calculated by assuming an across-the-board 10% increase or decrease in price regardless of term or historical relationships between the contractual price of the instruments and the underlying commodity price. In the event of an actual 10% change in prompt month prices, the fair value of our derivative portfolio would typically change less than that shown in the table due to lower volatility in out-month prices. We have a daily margin requirement to maintain a cash deposit with our brokers based on the prior day’s market results on open futures contracts. The balance of this deposit will fluctuate based on our open market positions and the commodity exchange’s requirements. The brokerage margin balance was $21.9 million at June 30, 2013.

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

Item 4. Controls and Procedures

Disclosure Controls and Procedures

We maintain disclosure controls and procedures that are designed to ensure that the information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act of 1934 (the “Exchange Act”) is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms and that information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure. Under the supervision and with the participation of our principal executive officer and principal financial officer, management evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) or 15d-15(e) of the Exchange Act). Based on that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of June 30, 2013.

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Internal Control over Financial Reporting

There has not been any change in our internal control over financial reporting that occurred during the quarter ended June 30, 2013 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

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. We are complying with the Requests for Information. We do not believe that a material violation has occurred nor do we believe any adverse determination in connection with such investigation would have a material impact on our operations.

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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, 2012, which could materially affect our business, financial condition or future results.

Item 6. Exhibits

2.1	**	—	Contribution Agreement dated November 21, 2011, by and among Global Partners LP and AE Holdings Corp. (incorporated herein by reference to Exhibit 2.1 to the Current Report on Form 8-K filed on November 23, 2011).

2.2		—	Exhibit A to Contribution Agreement (Exhibit 2.1), Determination of the Cash Adjustment (incorporated herein by reference to Exhibit 2.2 to the Current Report on Form 8-K filed on November 23, 2011).

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

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

4.1		—	Indenture, dated as of February 14, 2013, by and among Global Partners LP and GLP Finance Corp., as Issuers, the Guarantors party thereto and FS Energy and Power Fund, as Purchaser (incorporated herein by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on February 21, 2013).

10.1	^	—	Retirement, Consulting and Noncompete Agreement, dated April 23, 2013, by and between Global GP LLC and Thomas Hollister (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on April 26, 2013).

10.2	^	—	Form of Phantom Unit Award Agreement for Employees under Global Partners LP Long-Term Incentive Plan (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on July 3, 2013).

10.3	^	—	Form of Phantom Unit Award Agreement for Directors under Global Partners LP Long-Term Incentive Plan (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on July 3, 2013).

10.4	^	—	Executive Change of Control Agreement, effective July 1, 2013, by and between Global GP LLC and Daphne H. Foster (incorporated herein by reference to Exhibit 10.3 to the Current Report on Form 8-K filed on July 3, 2013).

10.5	^	—	Executive Change of Control Agreement, effective July 1, 2013, by and between Global GP LLC and Mark Romaine (incorporated herein by reference to Exhibit 10.4 to the Current Report on Form 8-K filed on July 3, 2013).

10.6	^	—	Executive Change of Control Agreement, effective July 1, 2013, by and between Global GP LLC and Charles A. Rudinsky (incorporated herein by reference to Exhibit 10.5 to the Current Report on Form 8-K filed on July 3, 2013).

10.7	^	—	Form of Confidentiality, Non-Solicitation, and Non-Competition Agreement for Phantom Unit Award Recipients (incorporated herein by reference to Exhibit 10.6 to the Current Report on Form 8-K filed on July 3, 2013).

10.8	^	—	Confidentiality, Non-Solicitation, and Non-Competition Agreement, effective July 1, 2013, by and between Global GP LLC and Daphne H. Foster (incorporated herein by reference to Exhibit 10.7 to the Current Report on Form 8-K filed on July 3, 2013).

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10.9	^	—	Confidentiality, Non-Solicitation, and Non-Competition Agreement, effective July 1, 2013, by and between Global GP LLC and Mark Romaine (incorporated herein by reference to Exhibit 10.8 to the Current Report on Form 8-K filed on July 3, 2013).

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	*	—	Interactive data files pursuant to Rule 405 of Regulation S-T: (i) Consolidated Statements of Income for the fiscal periods ended June 30, 2013 and 2012, (ii) Consolidated Balance Sheets at June 30, 2013 and December 31, 2012, (iii) Consolidated Statements of Comprehensive Income for the fiscal periods ended June 30, 2013 and 2012; (iv) Consolidated Statements of Cash Flows for the fiscal periods ended June 30, 2013 and 2012, (v) Consolidated Statements of Partners’ Equity for the fiscal period ended June 30, 2013 and (v) Notes to Consolidated Financial Statements.

** 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.

^ Management contract or compensatory plan or arrangement.

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

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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, 2013		By:	/s/ Eric Slifka
			Eric Slifka
			President and Chief Executive Officer
			(Principal Executive Officer)


Dated: August 8, 2013		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	**	—	Contribution Agreement dated November 21, 2011, by and among Global Partners LP and AE Holdings Corp. (incorporated herein by reference to Exhibit 2.1 to the Current Report on Form 8-K filed on November 23, 2011).

2.2		—	Exhibit A to Contribution Agreement (Exhibit 2.1), Determination of the Cash Adjustment (incorporated herein by reference to Exhibit 2.2 to the Current Report on Form 8-K filed on November 23, 2011).

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

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

4.1		—	Indenture, dated as of February 14, 2013, by and among Global Partners LP and GLP Finance Corp., as Issuers, the Guarantors party thereto and FS Energy and Power Fund, as Purchaser (incorporated herein by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on February 21, 2013).

10.1	^	—	Retirement, Consulting and Noncompete Agreement, dated April 23, 2013, by and between Global GP LLC and Thomas Hollister (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on April 26, 2013).

10.2	^	—	Form of Phantom Unit Award Agreement for Employees under Global Partners LP Long-Term Incentive Plan (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on July 3, 2013).

10.3	^	—	Form of Phantom Unit Award Agreement for Directors under Global Partners LP Long-Term Incentive Plan (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on July 3, 2013).

10.4	^	—	Executive Change of Control Agreement, effective July 1, 2013, by and between Global GP LLC and Daphne H. Foster (incorporated herein by reference to Exhibit 10.3 to the Current Report on Form 8-K filed on July 3, 2013).

10.5	^	—	Executive Change of Control Agreement, effective July 1, 2013, by and between Global GP LLC and Mark Romaine (incorporated herein by reference to Exhibit 10.4 to the Current Report on Form 8-K filed on July 3, 2013).

10.6	^	—	Executive Change of Control Agreement, effective July 1, 2013, by and between Global GP LLC and Charles A. Rudinsky (incorporated herein by reference to Exhibit 10.5 to the Current Report on Form 8-K filed on July 3, 2013).

10.7	^	—	Form of Confidentiality, Non-Solicitation, and Non-Competition Agreement for Phantom Unit Award Recipients (incorporated herein by reference to Exhibit 10.6 to the Current Report on Form 8-K filed on July 3, 2013).

10.8	^	—	Confidentiality, Non-Solicitation, and Non-Competition Agreement, effective July 1, 2013, by and between Global GP LLC and Daphne H. Foster (incorporated herein by reference to Exhibit 10.7 to the Current Report on Form 8-K filed on July 3, 2013).

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10.9	^	—	Confidentiality, Non-Solicitation, and Non-Competition Agreement, effective July 1, 2013, by and between Global GP LLC and Mark Romaine (incorporated herein by reference to Exhibit 10.8 to the Current Report on Form 8-K filed on July 3, 2013).

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	*	—	Interactive data files pursuant to Rule 405 of Regulation S-T: (i) Consolidated Statements of Income for the fiscal periods ended June 30, 2013 and 2012, (ii) Consolidated Balance Sheets at June 30, 2013 and December 31, 2012, (iii) Consolidated Statements of Comprehensive Income for the fiscal periods ended June 30, 2013 and 2012; (iv) Consolidated Statements of Cash Flows for the fiscal periods ended June 30, 2013 and 2012, (v) Consolidated Statements of Partners’ Equity for the fiscal period ended June 30, 2013 and (v) Notes to Consolidated Financial Statements.

* Filed herewith.

^ Management contract or compensatory plan or arrangement.

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