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, 2009

	OR

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

	For the transition period from to

Commission file number 001-32593

Global Partners LP

(Exact name of registrant as specified in its charter)

Delaware		74-3140887
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

P.O. Box 9161
800 South Street
Waltham, Massachusetts 02454-9161
(Address of principal executive offices, including zip code)

(781) 894-8800
(Registrant’s telephone number, including area code)

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Date 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 o 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 7,428,139 common units and 5,642,424 subordinated units outstanding as of August 4, 2009.

Table of Contents

TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Consolidated Balance Sheets as of June 30, 2009 and December 31, 2008

Consolidated Statements of Operations for the three and six months ended June 30, 2009 and 2008

Consolidated Statements of Cash Flows for the six months ended June 30, 2009 and 2008

Consolidated Statements of Partners’ Equity for the six months ended June 30, 2009

Notes to Consolidated Financial Statements

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

Item 3. Quantitative and Qualitative Disclosures about Market Risk

Item 4. Controls and Procedures

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

Item 1A. Risk Factors

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

Item 6. Exhibits

SIGNATURES

INDEX TO EXHIBITS

Table of Contents

Item 1. Financial Statements

GLOBAL PARTNERS LP

CONSOLIDATED BALANCE SHEETS

(In thousands, except unit data)

(Unaudited)

	June 30,			December 31,
	2009			2008
Assets
Current assets:
Cash and cash equivalents	$	2,962		$	945
Accounts receivable, net	190,621			249,418
Accounts receivable—affiliates	1,071			2,518
Inventories	369,353			240,346
Brokerage margin deposits	25,863			8,991
Fair value of forward fixed price contracts	8,598			161,787
Prepaid expenses and other current assets	31,570			29,302
Total current assets	630,038			693,307
Property and equipment, net	162,434			161,988
Intangible assets, net	29,939			31,403
Other assets	3,158			2,564
Total assets	$	825,569		$	889,262

Liabilities and partners’ equity
Current liabilities:
Accounts payable	$	132,223		$	219,783
Working capital revolving credit facility—current portion	135,814			208,210
Environmental liabilities—current portion	3,296			4,191
Accrued expenses and other current liabilities	63,776			54,054
Income taxes payable	—			520
Obligations on forward fixed price contracts	14,300			7,954
Total current liabilities	349,409			494,712
Working capital revolving credit facility—less current portion	228,986			154,090
Acquisition facility	71,200			71,200
Environmental liabilities—less current portion	2,314			2,377
Accrued pension benefit cost	9,103			8,853
Deferred compensation	1,752			1,663
Other long-term liabilities	9,294			12,899
Total liabilities	672,058			745,794

Partners’ equity
Common unitholders (7,428,139 units issued and 7,367,781 outstanding at June 30, 2009 and 7,428,139 units issued and outstanding at December 31, 2008)	166,335			163,092
Subordinated unitholders (5,642,424 units issued and outstanding at June 30, 2009 and December 31, 2008)	(1,274		)	(4,189		)
General partner interest (1.73% interest with 230,303 equivalent units outstanding at June 30, 2009 and December 31, 2008)	(53		)	(172		)
Accumulated other comprehensive loss	(11,497		)	(15,263		)
Total partners’ equity	153,511			143,468
Total liabilities and partners’ equity	$	825,569		$	889,262

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

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GLOBAL PARTNERS LP

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per unit data)

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008

Sales	$	1,201,149		$	2,297,709		$	2,834,104		$	5,018,701
Cost of sales	1,173,360			2,275,036			2,755,601			4,960,412
Gross profit	27,789			22,673			78,503			58,289

Costs and operating expenses:
Selling, general and administrative expenses	13,299			10,182			31,374			21,255
Operating expenses	9,137			8,771			17,612			17,796
Amortization expenses	803			737			1,603			1,461
Total costs and operating expenses	23,239			19,690			50,589			40,512

Operating income	4,550			2,983			27,914			17,777

Interest expense	(3,422		)	(4,087		)	(7,198		)	(10,117		)

Income (loss) before income tax expense	1,128			(1,104		)	20,716			7,660

Income tax expense	(150		)	(150		)	(875		)	(295		)

Net income (loss)	978			(1,254		)	19,841			7,365

Less: General partner’s interest in net income, including incentive distribution rights	(67		)	(28		)	(443		)	(227		)

Limited partners’ interest in net income (loss)	$	911		$	(1,282	)	$	19,398		$	7,138

Basic net income (loss) per limited partner unit	$	0.07		$	(0.10	)	$	1.48		$	0.55

Diluted net income (loss) per limited partner unit	$	0.07		$	(0.10	)	$	1.46		$	0.55

Basic weighted average limited partner units outstanding	13,059			13,071			13,065			13,071

Diluted weighted average limited partner units outstanding	13,356			13,071			13,273			13,071

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,
	2009			2008

Cash flows from operating activities
Net income	$	19,841		$	7,365
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation and amortization	7,460			7,111
Amortization of deferred financing fees	578			381
Loss on disposition of property and equipment and other	—			6
Bad debt expense	1,155			60
Stock-based compensation expense	917			390
Changes in operating assets and liabilities:
Accounts receivable	57,642			37,071
Accounts receivable – affiliate	1,447			(890		)
Inventories	(129,007		)	(3,153		)
Broker margin deposits	(16,872		)	(2,941		)
Prepaid expenses, all other current assets and other assets	(3,520		)	(5,442		)
Accounts payable	(87,559		)	(40,359		)
Income taxes payable	(578		)	109
Change in fair value of forward fixed price contracts	159,535			(7,491		)
Accrued expenses and all other current liabilities	9,142			1,810
Net cash provided by (used in) operating activities	20,181			(5,973		)

Cash flows from investing activities
Capital expenditures	(6,303		)	(5,523		)
Proceeds from sale of property and equipment	—			13
Net cash used in investing activities	(6,303		)	(5,510		)

Cash flows from financing activities
Proceeds from credit facilities, net	2,500			26,100
Payments on note payable, other	—			(1,239		)
Repurchase of common units	(1,293		)	—
Distributions to partners	(13,068		)	(13,068		)
Net cash (used in) provided by financing activities	(11,861		)	11,793

Increase in cash and cash equivalents	2,017			310
Cash and cash equivalents at beginning of period	945			2,110
Cash and cash equivalents at end of period	$	2,962		$	2,420

Supplemental information
Cash paid during the period for interest	$	7,289		$	10,320

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			Subordinated			Partner			Comprehensive			Partners’
	Unitholders			Unitholders			Interest			Loss			Equity

Balance at December 31, 2008	$	163,092		$	(4,189	)	$	(172	)	$	(15,263	)	$	143,468
Stock-based compensation	917			—			—			—			917
Phantom unit dividend	(8		)	—			—			—			(8		)
Distributions to partners	(7,242		)	(5,502		)	(324		)	—			(13,068		)
Repurchase of common units	(1,405		)	—			—			—			(1,405		)
Comprehensive income:
Net income	10,981			8,417			443			—			19,841
Other comprehensive income:
Change in fair value of interest rate collars	—			—			—			3,415			3,415
Change in pension liability	—			—			—			351			351
Total comprehensive income	—			—			—			—			23,607
Balance at June 30, 2009	$	166,335		$	(1,274	)	$	(53	)	$	(11,497	)	$	153,511

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 master limited partnership that engages in the wholesale and commercial distribution of refined petroleum products and small amounts of natural gas and provides ancillary services to companies.

The Partnership has five operating subsidiaries: Global Companies LLC, its subsidiary, Glen Hes Corp., Global Montello Group Corp., Chelsea Sandwich LLC and Global Energy Marketing LLC (“Global Energy”) (the five operating subsidiaries, collectively, the “Companies”). The Companies (other than Glen Hes Corp.) are wholly owned by Global Operating LLC, a wholly owned subsidiary of the Partnership. Global Energy was recently formed to expand the Partnership’s natural gas operations. It is in the process of obtaining licensure and is not yet operational. In addition, GLP Finance Corp. (“GLP Finance”) is a wholly owned subsidiary of the Partnership. GLP Finance has no material assets or liabilities. Its activities will be limited to co-issuing debt securities and engaging in other activities incidental thereto.

The Partnership’s 1.73% general partner interest is held by Global GP LLC, the Partnership’s general partner (the “General Partner”). The General Partner, which is owned by affiliates of the Slifka family, manages the Partnership’s operations and activities and employs its officers and substantially all of its personnel. The General Partner and affiliates of the General Partner, including its directors and executive officers, own 142,799 common units and 5,642,424 subordinated units, representing a combined 43.5% limited partner interest.

Basis of Presentation

Interim Financial Statements

The accompanying consolidated financial statements as of June 30, 2009 and December 31, 2008 and for the three and six months ended June 30, 2009 and 2008 reflect the accounts of the Partnership. All intercompany balances and transactions have been eliminated.

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, 2008 and notes thereto contained in the Partnership’s Annual Report on Form 10-K. The results of operations for the three and six months ended June 30, 2009 are not necessarily indicative of the results of operations that will be realized for the entire year ending December 31, 2009.

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, sales are generally higher during the first and fourth quarters of the calendar year which may result in significant fluctuations in the Partnership’s quarterly operating results.

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1. Organization and Basis of Presentation (continued)

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2009		2008		2009		2008
Distillate sales	35	%	40	%	51	%	50	%
Gasoline sales	60	%	56	%	43	%	45	%
Residual oil sales	5	%	4	%	6	%	5	%
	100	%	100	%	100	%	100	%

The Partnership had one customer, ExxonMobil Oil Corporation (“ExxonMobil”), who accounted for approximately 25% and 23% of total sales for the three months ended June 30, 2009 and 2008, respectively and approximately 19% and 20% of total sales for the six months ended June 30, 2009 and 2008, respectively.

The consolidated balance sheet at December 31, 2008 has been derived from the audited consolidated financial statements and footnotes thereto included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2008.

Reclassifications

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

Note 2. Net Income (Loss) Per Limited Partner Unit

On January 1, 2009, the Partnership adopted Emerging Issues Task Force (“EITF”) Issue No. 07-04, “Application of the Two-Class Method under FASB Statement No. 128 to Master Limited Partnerships” (“EITF 07-04”) which specifies the treatment of earnings per unit calculations when incentive distributions rights (“IDRs”) exist in master limited partnerships. EITF 07-04 provides that net income for the current period is to be reduced by the amount of available cash that will be distributed with respect to that period for purposes of calculating net income per unit. Any residual amount representing undistributed net income (or losses) is assumed to be allocated to the ownership interests in accordance with the contractual provisions of the partnership agreement.

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

On April 22, 2009, the board of directors of the General Partner declared a quarterly cash distribution of $0.4875 per unit for the period from January 1, 2009 through March 31, 2009. On July 23, 2009, the board declared a quarterly cash distribution of $0.4875 per unit for the period from April 1, 2009 through June 30, 2009. These declared cash distributions resulted in incentive distributions to the General Partner, as the holder of the incentive distribution rights, as indicated above, and enabled the Partnership to reach its second target distribution with respect to such incentive distribution rights. See Note 9, “Cash Distributions” for further information.

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 2. Net Income (Loss) 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, 2009 (in thousands, except per unit data):

	Three months ended June 30, 2009
				Limited			General Partner Interest
				Partner			General
	Total			Interest			Partner			IDRs
Numerator:
Net income	$	978		$	911		$	67		$	—

Declared distribution	$	6,534		$	6,372		$	112		$	50
Assumed allocation of undistributed net income	(5,556		)	(5,461		)	(95		)	—
Assumed allocation of net income	$	978		$	911		$	17		$	50

Denominator:
Basic weighted average limited partner units outstanding				13,059
Dilutive effect of phantom units				297
Diluted weighted average limited partner units outstanding				13,356

Basic net income per limited partner unit				$	0.07
Diluted net income per limited partner unit				$	0.07

	Six months ended June 30, 2009
			Limited		General Partner Interest
			Partner		General
	Total		Interest		Partner		IDRs
Numerator:
Net income	$	19,841	$	19,398	$	443	$	—

Declared distribution	$	13,068	$	12,744	$	224	$	100
Assumed allocation of undistributed net income	6,773		6,654		119		—
Assumed allocation of net income	$	19,841	$	19,398	$	343	$	100

Denominator:
Basic weighted average limited partner units outstanding			13,065
Dilutive effect of phantom units			208
Diluted weighted average limited partner units outstanding			13,273

Basic net income per limited partner unit			$	1.48
Diluted net income per limited partner unit			$	1.46

At June 30, 2009, limited partner units outstanding excluded common units held on behalf of the Partnership pursuant to its Repurchase Program and for future satisfaction of the General Partner’s Obligations (as defined in Note 12). These units are not deemed outstanding for purposes of calculating net income per limited partner unit (basic and diluted).

The Partnership applied the provisions of EITF No. 07-04 on a retroactive basis which had an immaterial impact on the limited partners’ interest in net (loss) income and net (loss) income per limited partner unit for the three and six months ended June 30, 2008.

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 2. Net Income (Loss) Per Limited Partner Unit (continued)

The following table provides a reconciliation of net (loss) income and the assumed allocation of net (loss) income to the limited partners’ interest for purposes of computing net income per limited partner unit for the three and six months ended June 30, 2008 (in thousands, except per unit data):

	Three months ended June 30, 2008
				Limited			General Partner Interest
				Partner			General
	Total			Interest			Partner			IDRs
Numerator:
Net loss	$	(1,254	)	$	(1,282	)	$	28		$	—

Declared distribution	$	6,534		$	6,372		$	112		$	50
Assumed allocation of undistributed net loss	(7,788		)	(7,654		)	(134		)	—
Assumed allocation of net loss	$	(1,254	)	$	(1,282	)	$	(22	)	$	50

Denominator:
Basic weighted average limited partner units outstanding				13,071
Diluted weighted average limited partner units outstanding				13,071

Basic net loss per limited partner unit				$	(0.10	)
Diluted net loss per limited partner unit				$	(0.10	)

	Six months ended June 30, 2008
				Limited			General Partner Interest
				Partner			General
	Total			Interest			Partner			IDRs
Numerator:
Net income	$	7,365		$	7,138		$	227		$	—

Declared distribution	$	13,068		$	12,744		$	224		$	100
Assumed allocation of undistributed net income	(5,703		)	(5,606		)	(97		)	—
Assumed allocation of net income	$	7,365		$	7,138		$	127		$	100

Denominator:
Basic weighted average limited partner units outstanding				13,071
Diluted weighted average limited partner units outstanding				13,071

Basic net income per limited partner unit				$	0.55
Diluted net income per limited partner unit				$	0.55

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 3. Comprehensive Income

The components of comprehensive income consisted of the following (in thousands):

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2009		2008			2009		2008
Net income (loss)	$	978	$	(1,254	)	$	19,841	$	7,365
Change in fair value of interest rate collars	2,263		2,280			3,415		(116		)
Change in pension liability	593		(217		)	351		(781		)
Total comprehensive income	$	3,834	$	809		$	23,607	$	6,468

Note 4. Inventories

The Partnership hedges substantially all of its inventory purchases through futures contracts and swap agreements. Hedges are executed when inventory is purchased and are identified with that specific inventory. 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.

Inventories consisted of the following (in thousands):

	June 30, 2009		December 31, 2008
Distillates: home heating oil, diesel and kerosene	$	251,553	$	160,000
Residual oil	31,003		24,878
Gasoline	69,644		40,183
Blend stock	17,153		15,285
Total	$	369,353	$	240,346

In addition to its own inventory, the Partnership has exchange agreements 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 $21.8 million and $14.8 million at June 30, 2009 and December 31, 2008, respectively. Negative exchange balances are accounted for as accounts payable and amounted to $11.5 million and $8.4 million at June 30, 2009 and December 31, 2008, respectively. Exchange transactions are valued using current quoted market prices.

Note 5. Derivative Financial Instruments

Statement of Financial Accounting Standards (“SFAS”) No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended (“SFAS No. 133”) establishes accounting and reporting standards for derivative instruments and hedging activities and 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.

Effective January 1, 2009, the Partnership adopted SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities — An Amendment of FASB Statement No. 133” (“SFAS No. 161”) which changes the disclosure requirements for derivative and hedging activities. SFAS No. 161 requires the Partnership to provide enhanced disclosures about (a) how and why the Partnership uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under SFAS No. 133 and its related interpretations, and (c) how derivative instruments and related hedged items affect the Partnership’s financial position, financial performance and cash flows.

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GLOBAL PARTNERS LP

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, 2009:

	Units(1)			Unit of Measure
Oil Contracts
Long	8,779			Thousands of barrels
Short	(11,760		)	Thousands of barrels

Natural Gas Contracts
Long	19,962			Decatherms
Short	(19,962		)	Decatherms

Interest Rate Collars	$	200,000		Thousands of 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 cash settlements under the contracts.

Fair Value Hedges

The fair value of the Partnership’s derivatives is determined through the use of independent markets and is based upon the prevailing market prices of such instruments at the date of valuation. The Partnership enters into futures contracts for the receipt or delivery of refined petroleum products in future periods. The contracts are entered into in the normal course of business to reduce risk of loss of inventory on hand, which could result through fluctuations in market prices. 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. Ineffectiveness related to these hedging activities was immaterial at June 30, 2009.

The Partnership also uses futures contracts and swap agreements to hedge exposure under forward purchase and sale commitments. These agreements are intended to hedge the cost component of virtually all of the Partnership’s forward purchase and sale commitments. Changes in the fair value of these contracts, as well as offsetting gains or losses on the forward fixed price purchase and sale commitments, are recognized in earnings as an increase or decrease in cost of sales. Gains and losses on net product margin from forward fixed price purchase and sale contracts are reflected in earnings as an increase or decrease in cost of sales as these contracts mature. Ineffectiveness related to these hedging activities was immaterial at June 30, 2009.

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 5. Derivative Financial Instruments (continued)

The following table presents the gross fair values of the Partnership’s derivative instruments and firm commitments and their location in the Partnership’s consolidated balance sheets at June 30, 2009 and December 31, 2008 (in thousands):

	Assets					Liabilities
		June 30,		December 31,			June 30,		December 31,
Derivatives Under	Balance Sheet	2009		2008		Balance Sheet	2009		2008
SFAS No. 133	Location	Fair Value		Fair Value		Location	Fair Value		Fair Value

Derivatives designated as hedging instruments and firm commitments

Oil product contracts(1)	(2)	$	60,311	$	215,237	(3)	$	68,762	$	57,506

Derivatives not designated as hedging instruments

Oil product contracts	Accrued expenses and other current liabilities	7,411		6,739		Accrued expenses and other current liabilities	7,491		6,799

Total derivatives		$	67,772	$	221,976		$	76,253	$	64,305

(1) Includes forward fixed price purchase and sale contracts as recognized in the Partnership’s consolidated balance sheets at June 30, 2009 and December 31, 2008.

(2) Fair value of forward fixed price contracts, prepaid expenses and other current assets, accrued and other current liabilities and obligations on forward fixed price contracts

(3) Obligations on forward fixed price contracts and accrued expenses and other current liabilities

The following table presents the amount of gains and losses 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, 2009 and 2008 (in thousands):

Amount of Gain (Loss)

Hedged

Location of

Amount of Gain (Loss)

Derivatives in

Location of

Recognized in Income

Items in

Gain (Loss)

Recognized in Income

SFAS No. 133

Gain (Loss)

on Derivatives

SFAS No. 133

Recognized in

on Hedged Items

Fair Value

Recognized in

Three Months Ended

Fair Value

Income on

Three Months Ended

Hedging

Income on

June 30,

Hedge

Related

June 30,

Relationship

Derivative

2009

2008

Relationships

Hedged Item

2009

2008

Oil product contracts

Cost of sales

(99,378

)

(85,417

)

Inventories and forward fixed price contracts

Cost of sales

99,699

85,741

Amount of Gain (Loss)

Hedged

Location of

Amount of Gain (Loss)

Derivatives in

Location of

Recognized in Income

Items in

Gain (Loss)

Recognized in Income

SFAS No. 133

Gain (Loss)

on Derivatives

SFAS No. 133

Recognized in

on Hedged Items

Fair Value

Recognized in

Six Months Ended

Fair Value

Income on

Six Months Ended

Hedging

Income on

June 30,

Hedge

Related

June 30,

Relationship

Derivative

2009

2008

Relationships

Hedged Item

2009

2008

Oil product contracts

Cost of sales

(199,602

)

(82,886

)

Inventories and forward fixed price contracts

Cost of sales

200,247

83,200

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 5. Derivative Financial Instruments (continued)

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

The table below presents the composition and fair value of forward fixed price purchase and sale contracts on the Partnership’s consolidated balance sheet being hedged by the following derivative instruments (in thousands):

	June 30, 2009			December 31, 2008
Futures contracts, net	$	(2,642	)	$	138,741
Swaps and other, net	(3,060		)	15,092
Total	$	(5,702	)	$	153,833

The total balances of $(5.7 million) and $153.8 million reflect the fair value of the forward fixed price contract (liability)/asset net of the corresponding asset/(liability) on the accompanying consolidated balance sheets at June 30, 2009 and December 31, 2008, respectively.

The Partnership also markets and sells natural gas. The Partnership generally conducts business by entering into forward purchase commitments for natural gas only when it simultaneously enters into arrangements for the sale of product for physical delivery to third-party users. The Partnership generally takes delivery under its purchase commitments at the same location as it delivers to third-party users. Through these transactions, which establish an immediate margin, the Partnership seeks to maintain a position that is substantially balanced between firm forward purchase and sales commitments. Natural gas is generally purchased and sold at fixed prices and quantities. Current price quotes from actively traded markets are used in all cases to determine the contracts’ fair value. Changes in the fair value of these contracts are recognized in earnings as an increase or decrease in cost of sales.

The Partnership formally documents all relationships between hedging instruments and hedged items after its risk management objectives and strategy for undertaking the hedge are determined. The Partnership calculates hedge effectiveness on a quarterly basis. This process includes specific identification of the hedging instrument and the hedged transaction, the nature of the risk being hedged and how the hedging instrument’s effectiveness will be assessed. Both at the inception of the hedge and on an ongoing basis, the Partnership assesses whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in fair value of hedged items. The derivative instruments that qualify for hedge accounting are fair value hedges.

The Partnership has a daily margin requirement with its broker based on the prior day’s market results on open futures contracts. The required brokerage margin balance was $25.9 million and $9.0 million at June 30, 2009 and December 31, 2008, respectively.

The Partnership is exposed to credit loss in the event of nonperformance by counterparties of forward purchase and sale commitments, futures contracts, options 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 one clearing broker, a major financial institution, for all New York Mercantile Exchange (“NYMEX”) derivative transactions and the right of offset exists. Accordingly, the fair value of all derivative instruments is presented on a net basis on the consolidated balance sheets. Exposure on forward purchase and sale commitments, swap and certain option agreements is limited to the amount of the recorded fair value as of the balance sheet dates.

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 5. Derivative Financial Instruments (continued)

Cash Flow Hedges

The Partnership links all hedges that are designated as cash flow hedges to forecasted transactions. To the extent such hedges are effective, the changes in the fair value of the derivative instrument is reported as a component of other comprehensive income and reclassified into earnings in the same period during which the hedged transaction affects earnings.

The Partnership executed two zero premium interest rate collars with major financial institutions. Each collar is designated as a cash flow hedge and accounted for under the provisions of SFAS No. 133. The first collar, which became effective on May 14, 2007 and expires on May 14, 2011, is used to hedge the variability in interest payments due to changes in the three-month LIBOR rate with respect to $100.0 million of three-month LIBOR-based borrowings. Under the first collar, the Partnership capped its exposure at a maximum three-month LIBOR rate of 5.75% and established a minimum floor rate of 3.75%. As of June 30, 2009, the three-month LIBOR rate of 0.91% was lower than the floor rate. As a result, in August 2009, the Partnership will remit to the respective financial institution the difference between the floor rate and the current rate which amounted to approximately $379,000 and, at June 30, 2009, was recorded in accrued expenses and other current liabilities on the accompanying consolidated balance sheet. As of June 30, 2009, the fair value of the first collar was a liability of approximately $4.4 million and was recorded in both other long-term liabilities and accumulated other comprehensive income. Hedge effectiveness was assessed at inception and is assessed quarterly, prospectively and retrospectively. The changes in the fair value of the first collar are expected to be highly effective in offsetting the changes in interest rate payments attributable to fluctuations in the three-month LIBOR rate above and below the first collar’s strike rates. Ineffectiveness related to the first collar was immaterial at June 30, 2009.

On September 29, 2008, the Partnership executed its second zero premium interest rate collar. The second 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 the Partnership’s $100.0 million one-month LIBOR-based borrowings (and subsequent refinancings thereof) due to changes in the one-month LIBOR rate. Under the second collar, the Partnership capped its exposure at a maximum one-month LIBOR rate of 5.50% and established a minimum floor rate of 2.70%. As of June 30, 2009, the one-month LIBOR rate of 0.32% was lower than the floor rate. As a result, in July 2009, the Partnership remitted to the respective financial institution the difference between the floor rate and the current rate which amounted to approximately $192,000 and, at June 30, 2009, was recorded in accrued expenses and other current liabilities on the accompanying consolidated balance sheet. As of June 30, 2009, the fair value of the second collar was a liability of approximately $3.0 million and was recorded in both other long-term liabilities and accumulated other comprehensive income in the accompanying consolidated balance sheet. Hedge effectiveness was assessed at inception and is assessed quarterly, prospectively and retrospectively, using the regression analysis. The changes in the fair value of the second collar are expected to be highly effective in offsetting the changes in interest rate payments attributable to fluctuations in the one-month LIBOR rate above and below the second collar’s strike rates. Ineffectiveness related to the second collar was immaterial at June 30, 2009.

The following table presents the fair value of the Partnership’s derivative instruments and their location in the Partnership’s consolidated balance sheets at June 30, 2009 and December 31, 2008 (in thousands):

Assets

Liabilities

June 30,

December 31,

June 30,

December 31,

Derivatives Under

Balance Sheet

2009

2008

Balance Sheet

2009

2008

SFAS No. 133

Location

Fair Value

Location

Fair Value

Derivatives designated as hedging instruments

Interest rate collars

—

Other long-term liabilities

7,431

10,846

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 5. Derivative Financial Instruments (continued)

The following table presents the amount of gains and losses from derivatives involved in cash flow hedging relationships recognized in the Partnership’s consolidated statements of income for the three and six months ended June 30, 2009 and 2008 (in thousands):

Recognized in Income

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

Derivatives in

on Derivatives

Testing)

on Derivatives

Testing)

SFAS No. 133

Three Months Ended

Six Months Ended

Cash Flow

June 30,

Hedging Relationship

2009

2008

2009

2008

2009

2008

2009

2008

Interest rate collars

2,264

2,280

—

3,416

(116

)

—

Ineffectiveness related to the interest rate collars is recognized as interest expense and was immaterial at June 30, 2009. The effective portion related to the interest rate collars that was originally reported in other comprehensive income and reclassified to earnings was $1.3 million and $2.3 million for the three and six months ended June 30, 2009, respectively.

Derivatives Not Involved in a SFAS No. 133 Relationship

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 logistical issues associated with inclement weather conditions. In connection with managing these positions and maintaining a constant presence in the marketplace, both necessary for its business, the Partnership engages in a controlled trading program for up to an aggregate of 250,000 barrels of refined petroleum products at any one point in time.

The following table presents the amount of gains and losses from derivatives not involved in a SFAS No. 133 hedging relationships recognized in the Partnership’s consolidated statements of income for the three and six months ended June 30, 2009 and 2008 (in thousands):

Amount of Gain (Loss)

Location of

Recognized in Income

Gain (Loss)

on Derivatives

Recognized in

Three Months Ended

Six Months Ended

Derivatives Not Designated as Hedging

Income on

June 30,

Instruments Under SFAS No. 133

Derivatives

2009

2008

2009

2008

Oil product contracts

Cost of sales

1,767

(1,051

)

5,752

4,503

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 6. Debt

The Partnership has a senior secured credit agreement (the “Credit Agreement”) with total available commitments of $750.0 million. There are 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 $650.0 million; the $650.0 million includes two $50.0 million seasonal overline facilities that are available each year only during the period between September 1 and June 30;

· an $85.0 million acquisition facility to be used for funding acquisitions similar to the Partnership’s business line that have a purchase price of $25.0 million or less or $35.0 million or less in the aggregate in any 12-month period; and

· a $15.0 million revolving credit facility to be used for general purposes, including payment of distributions to the Partnership’s unitholders.

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: (1) the acquisition facility by up to another $50.0 million, for a total acquisition facility of up to $135.0 million; and (2) the working capital revolving credit facility by up to another $200.0 million, for a total working capital revolving credit facility of up to $850.0 million. Any such request for an increase by the Partnership must be in a minimum amount of $5.0 million, and no more than three such requests may be made for each facility. The Partnership, however, cannot provide assurance that its lending group will agree to fund any request by the Partnership for additional amounts in excess of the total available commitments of $750.0 million.

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 can borrow only up to the level of its 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 refined petroleum product prices, collection cycles, counterparty performance, advance rates and limits and deteriorating 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.

During the period from January 1, 2008 through July 20, 2008, borrowings under the Partnership’s working capital revolving credit, acquisition and revolving credit facilities bore interest at the Partnership’s option at (1) the Eurodollar rate, plus 1%, 1½% and 1½%, respectively, (2) the cost of funds rate, plus 1%, 1¾% and 1½%, respectively, or (3) the bank’s base rate.

Commencing July 21, 2008, borrowings under the working capital revolving credit facility bear interest at (1) the Eurodollar rate plus 1.75% to 2.25%, (2) the cost of funds rate plus 1.75% to 2.25%, or (3) the base rate plus 0.75% to 1.25%, each depending on the pricing level provided in the Credit Agreement, as amended, which in turn depends upon the Combined Interest Coverage Ratio (as such term is defined in the Credit Agreement). Commencing July 21, 2008, borrowings under the acquisition and revolving credit facilities bear interest at (1) the Eurodollar rate plus 2.25% to 2.75%, (2) the cost of funds rate plus 1.75% to 2.25%, or (3) the base rate plus 0.75% to 1.25%, each depending on the pricing level provided in the Credit Agreement, as amended, which in turn depends upon the Combined Interest Coverage Ratio. The average interest rate was approximately 3.8% for each of the three months ended June 30, 2009 and 2008. The average interest rates were approximately 3.8% and 4.2% for the six months ended June 30, 2009 and 2008, respectively.

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 6. Debt (continued)

In addition, the Partnership executed two zero premium interest rate collars with major financial institutions. The first collar, which became effective on May 14, 2007, is used to hedge the variability in interest payments due to changes in the three-month LIBOR rate with respect to $100.0 million of three-month LIBOR-based borrowings. The second collar, which became effective on October 2, 2008, is used to hedge the variability in cash flows in monthly interest payments made on the Partnership’s $100.0 million one-month LIBOR-based borrowings (and subsequent refinancings thereof) due to changes in the one-month LIBOR rate (see Note 5 for further discussion on the interest rate collars).

The Partnership incurs a letter of credit fee of 1.75% per annum for each letter of credit issued. In addition, the Partnership incurs a commitment fee on the unused portion of the three facilities under the Credit Agreement (including the unused portion of either of the seasonal overline facilities exercised by the Partnership) equal to 0.3% to 0.375% per annum, depending on the pricing level and the Combined Interest Coverage Ratio provided in the Credit Agreement. The Partnership also incurs a facility fee of 0.1% per annum on any unexercised seasonal overline facility during the period between September 1 and June 30 and a seasonal overline fee of $30,000 each time the Partnership elects to exercise either of the seasonal overline facilities.

The Credit Agreement will mature on April 22, 2011. 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 $229.0 million and $154.1 million at June 30, 2009 and December 31, 2008, respectively, representing the amounts expected to be outstanding during the 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 $135.8 million and $208.2 million at June 30, 2009 and December 31, 2008, respectively, representing the amounts the Partnership expects to pay down during the course of the year.

As of June 30, 2009, the Partnership had total borrowings outstanding under the Credit Agreement of $436.0 million, including $71.2 million outstanding on the acquisition facility. In addition, the Partnership had outstanding letters of credit of $54.0 million. The total remaining availability for borrowings and letters of credit at June 30, 2009 and December 31, 2008 was $260.0 million and $211.3 million, respectively.

The Credit Agreement is secured by substantially all of the assets of the Partnership and each of the Companies 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, 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 EBITDA ratio, a minimum combined interest coverage ratio and a maximum leverage ratio. The Partnership was in compliance with the foregoing covenants at June 30, 2009. 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).

The Credit Agreement also requires that in each calendar year, the outstanding amount under the working capital revolving credit facility must be equal to or less than $263.0 million for a period of ten consecutive calendar days. The Partnership has complied with this provision for the year ending December 31, 2009.

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 6. Debt (continued)

The Credit Agreement limits distributions by the Partnership to its unitholders to the amount of the Partnership’s available cash and permits borrowings to fund such distributions only under the $15.0 million revolving credit facility. The revolving credit facility is subject to an annual “clean-down” period, requiring the Partnership to reduce the amount outstanding under the revolving credit facility to $0 for 30 consecutive calendar days in each calendar year. The Partnership has complied with this provision for the year ending December 31, 2009.

The lending group under the Credit Agreement includes the following institutions: Bank of America, N.A.; Standard Chartered Bank; JPMorgan Chase Bank, N.A.; Societe Generale; RBS Citizens, National Association; Sovereign Bank; Fortis Capital Corp.; Webster Bank National Association; KeyBank National Association; TD Bank, N.A. (f/k/a TD BankNorth, N.A.); Wells Fargo Bank, N.A.; Wachovia Bank, National Association; and Calyon New York Branch.

Note 7. Employee Benefit Plan with Related Party

The General Partner employs substantially all of the Partnership’s employees and charges the Partnership for their services. The Partnership also reimburses the General Partner for its contributions under the General Partner’s 401(k) Savings and Profit Sharing Plan and the General Partner’s qualified and non-qualified pension plans. The Partnership’s net periodic benefit cost for the defined benefit pension plan consisted of the following components (in thousands):

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
Service cost	$	325		$	266		$	650		$	531
Interest cost	228			200			457			400
Expected return on plan assets	(160		)	(165		)	(321		)	(330		)
Recognized net actuarial loss	48			—			96			—
Net periodic benefit cost	$	441		$	301		$	882		$	601

Note 8. Related Party Transactions

The Partnership is a party to a Second Amended and Restated Terminal Storage Rental and Throughput Agreement with Global Petroleum Corp. (“GPC”), an affiliate of the Partnership, which extends through December 2013 with annual renewal options thereafter. The agreement is accounted for as an operating lease. The expenses under this agreement totaled approximately $2.1 million for each of the three months ended June 30, 2009 and 2008 and approximately $4.2 million for each of the six months ended June 30, 2009 and 2008.

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 $15,000 and $21,500 for the three months ended June 30, 2009 and 2008, respectively, and approximately $36,500 and $43,000 for the six months ended June 30, 2009 and 2008, respectively. These charges were recorded in selling, general and administrative expenses in the accompanying consolidated statements of operations. 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 after January 1, 2009. As of June 30, 2009, no such notice of termination was given by either party.

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 8. Related Party Transactions (continued)

Pursuant to the Partnership’s Amended and Restated Services Agreement with Alliance Energy LLC (formerly known as Alliance Energy Corp.) (“Alliance”), the Partnership also provides certain administrative, accounting and information processing services, and the use of certain facilities, to Alliance, an affiliate of the Partnership that is wholly owned by AE Holdings Corp., which is approximately 95% owned by members of the Slifka family. The income from these services was approximately $78,800 and $216,500 for the three months ended June 30, 2009 and 2008, respectively, and $191,000 and $433,000 for the six months ended June 30, 2009 and 2008, respectively. These fees were recorded as an offset to selling, general and administrative expenses in the accompanying consolidated statements of operations. The agreement extends through January 1, 2010.

The Partnership sells refined petroleum products to Alliance at prevailing market prices at the time of delivery. Sales to Alliance were approximately $3.9 million and $13.6 million for the three months ended June 30, 2009 and 2008, respectively, and $6.6 million and $19.4 million for the six months ended June 30, 2009 and 2008, respectively.

The General Partner employs substantially all of the Partnership’s employees and charges the Partnership for their services. The expenses for the three months ended June 30, 2009 and 2008, including payroll, payroll taxes and bonus accruals, were $7.6 million and $6.7 million, respectively, and $19.9 million and $14.4 million for the six months ended June 30, 2009 and 2008, respectively. The Partnership also reimburses the General Partner for its contributions under the General Partner’s 401(k) Savings and Profit Sharing Plan and the General Partner’s qualified and non-qualified pension plans.

The table below presents trade receivables with Alliance, receivables incurred in connection with the services agreements between Alliance and the Partnership and GPC and the Partnership, as the case may be, and receivables from the General Partner (in thousands):

	June 30, 2009		December 31, 2008
Receivables from Alliance	$	446	$	383
Receivables from GPC	222		325
Receivables from the General Partner (1)	403		1,810
Total	$	1,071	$	2,518

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

Note 9. 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 cash flows, 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 at the end of the quarter; plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of 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 to the General Partner for any one or more of the next four quarters. Working capital borrowings are generally borrowings that are made under the Credit Agreement and in all cases are used solely for working capital purposes or to pay distributions to partners.

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 9. Cash Distributions (continued)

The Partnership will make distributions of available cash from operating surplus for any quarter during the subordination period as defined in its partnership agreement in the following manner: firstly, 98.27% to the common unitholders, pro rata, and 1.73% to the General Partner, until the Partnership distributes for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter; secondly, 98.27% to the common unitholders, pro rata, and 1.73% to the General Partner, until the Partnership distributes for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period; thirdly, 98.27% to the subordinated unitholders, pro rata, and 1.73% to the General Partner, until the Partnership distributes for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and thereafter, cash in excess of the minimum quarterly distributions is distributed to the unitholders and the General Partner, as the holder of the incentive distribution rights, based on the percentages as provided below.

As the holder of the incentive distribution rights, 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	$0.4125	98.27	%	1.73	%
First Target Distribution	Up to $0.4625	98.27	%	1.73	%
Second Target Distribution	above $0.4625 up to $0.5375	85.27	%	14.73	%
Third Target Distribution	above $0.5375 up to $0.6625	75.27	%	24.73	%
Thereafter	above $0.6625	50.27	%	49.73	%

The Partnership paid the following cash distribution during 2009 (in thousands, except per unit data):

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

02/13/09(1)	$	0.4875	$	3,621	$	2,751	$	112	$	50	$	6,534
05/15/09(2)	$	0.4875	$	3,621	$	2,751	$	112	$	50	$	6,534

(1) This distribution of $0.4875 per unit resulted in the Partnership reaching its second target distribution for the fourth quarter of 2008. As a result, the General Partner, as the holder of the IDRs, received this additional incentive distribution.

(2) This distribution of $0.4875 per unit resulted in the Partnership reaching its second target distribution for the first quarter of 2009. As a result, the General Partner, as the holder of the IDRs received this additional incentive distribution.

In addition, on July 23, 2009, the board of directors of the General Partner declared a quarterly cash distribution of $0.4875 per unit for the period from April 1, 2009 through June 30, 2009 ($1.95 per unit on an annualized basis). On August 14, 2009, the Partnership will pay this cash distribution to its common and subordinated unitholders of record as of the close of business August 5, 2009. This distribution will result in the Partnership reaching its second target distribution for the quarter ended June 30, 2009.

Note 10. Segment Reporting

The Partnership is a wholesale and commercial distributor of gasoline, distillates and residual oil whose business is organized within two operating segments, Wholesale and Commercial, based on the way the chief operating decision maker (CEO) manages the business and on the similarity of customers and expected long-term financial performance of each segment. 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, 2008.

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 10. Segment Reporting (continued)

In the Wholesale segment, the Partnership sells gasoline, home heating oil, diesel, kerosene and residual oil to unbranded retail gasoline stations and other resellers of transportation fuels, home heating oil retailers and wholesale distributors. Generally, customers use their own vehicles or contract carriers to take delivery of the product at bulk terminals and inland storage facilities that the Partnership owns or controls or with which it has throughput arrangements.

The Commercial segment includes (1) sales and deliveries of unbranded gasoline, home heating oil, diesel, kerosene, residual oil and small amounts of natural gas to customers in the public sector and to large commercial and industrial customers, either through a competitive bidding process or through contracts of various terms, and (2) sales of custom blended distillates and residual oil delivered by barges or from a terminal dock. Commercial segment 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 limited group of small utilities. Unlike the Wholesale segment, in the Commercial segment, the Partnership generally arranges the delivery of the product to the customer’s designated location, typically hiring 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 CEO manages the business, it is not reasonably possible for the Partnership to allocate the components of operating costs and expenses between the reportable segments. Additionally, due to the commingled nature and uses of the Partnership’s assets, it is not reasonably possible for the Partnership to allocate assets between the two segments. There were no intersegment sales for any of the periods presented below.

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,
	2009		2008		2009		2008
Wholesale Segment:
Sales
Distillates	$	405,060	$	883,577	$	1,411,676	$	2,486,987
Gasoline	720,330		1,283,676		1,221,989		2,258,744
Residual oil	5,853		25,220		17,343		43,577
Total	$	1,131,243	$	2,192,473	$	2,651,008	$	4,789,308
Net product margin (1)
Distillates	$	13,477	$	9,329	$	47,330	$	32,421
Gasoline	12,127		10,424		23,913		18,968
Residual oil	2,294		3,234		5,114		7,130
Total	$	27,898	$	22,987	$	76,357	$	58,519
Commercial Segment:
Sales	$	69,906	$	105,236	$	183,096	$	229,393
Net product margin (1)	$	2,596	$	2,323	$	7,524	$	4,929
Combined sales and net product margin:
Sales	$	1,201,149	$	2,297,709	$	2,834,104	$	5,018,701
Net product margin (1)	$	30,494	$	25,310	$	83,881	$	63,448
Depreciation allocated to cost of sales	2,705		2,637		5,378		5,159
Combined gross profit	$	27,789	$	22,673	$	78,503	$	58,289

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

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Note 10. 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,
	2009			2008			2009			2008
Combined gross profit	$	27,789		$	22,673		$	78,503		$	58,289
Operating costs and expenses not allocated to reportable segments:
Selling, general and administrative expenses	13,299			10,182			31,374			21,255
Operating expenses	9,137			8,771			17,612			17,796
Amortization expenses	803			737			1,603			1,461
Total operating costs and expenses	23,239			19,690			50,589			40,512
Operating income	4,550			2,983			27,914			17,777
Interest expense	(3,422		)	(4,087		)	(7,198		)	(10,117		)
Income tax expense	(150		)	(150		)	(875		)	(295		)
Net income (loss)	$	978		$	(1,254	)	$	19,841		$	7,365

There were no foreign sales for the three and six months ended June 30, 2009 and 2008. The Partnership has no foreign assets.

Note 11. Environmental Liabilities

The Partnership currently owns or leases properties where refined petroleum products are being or have been handled. These properties and the refined petroleum products 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 to 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 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, of which approximately $0.6 million was paid by the Partnership. The remaining liability of $0.6 million was recorded as a current liability of $0.4 million and a long-term liability of $0.2 million on the accompanying consolidated balance sheet at June 30, 2009. The remedial action plans submitted by ExxonMobil have been implemented by Global Companies LLC. The Partnership does not believe that compliance with the terms thereof will result in material costs in excess of the environmental reserve or have a material impact on its operations.

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Note 11. Environmental Liabilities (continued)

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, of which approximately $0.1 million was paid for the year ended December 31, 2008 for a balance of $7.9 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. At June 30, 2009, this liability had a balance of $5.0 million which was recorded as a current liability of $2.9 million and a long-term liability of $2.1 million on the accompanying consolidated balance sheet. 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 Partnership does not believe that compliance with the terms of the approved remedial action work plan will result in material costs in excess of the environmental reserve or have a material impact on its operations.

Global Companies LLC, in addition to several affiliates, was named as one of over 50 defendants in two lawsuits alleging methyl tertiary-butyl ether (“MTBE”) contamination of groundwater in Massachusetts. MTBE is an oxygenate that has been used extensively to reduce motor vehicle tailpipe emissions. In the cases of Town of Duxbury, et al. v. Amerada Hess Corp., et al., filed December 31, 2003, and City of Lowell v. Amerada Hess Corp., et al., filed December 30, 2004, plaintiffs allege that manufacturers, refiners and others involved in the distribution of gasoline containing MTBE are liable for the costs of investigating possible MTBE groundwater contamination, treating such contaminated groundwater where found, and related relief including treble damages and injunctive relief. The plaintiffs in these cases generally claim to be public water providers or municipal or other government authorities. These cases have been consolidated in multi-district litigation with over 60 other MTBE cases in federal court in the Southern District of New York. The Partnership entered into an agreement to settle these cases and, as a result, the Partnership paid $0.9 million during the quarter ended June 30, 2009. The matter with respect to Global Companies LLC and affiliates has been dismissed.

The Partnership’s estimates used in these reserves 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 and the possibility of existing legal claims giving rise to additional claims. Therefore, although the Partnership believes that these reserves are adequate, no assurances can be made that any costs incurred in excess of these reserves 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.

Note 12. Long-Term Incentive Plan

In October 2005, the General Partner adopted a Long-Term Incentive Plan (“LTIP”) whereby 564,242 common units were authorized for issuance. Any units delivered pursuant to an award under the LTIP may be acquired in the open market or from any affiliate, be newly issued units or any combination of the foregoing. The LTIP provides for awards to employees, consultants and directors of the General Partner and employees and consultants of affiliates of the Partnership who perform services for the Partnership. The LTIP allows for the award of unit options, unit appreciation rights, restricted units, phantom units and distribution equivalent rights (“DERs”).

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Note 12. Long-Term Incentive Plan (continued)

Long-Term Incentive Plan

On August 14, 2007, the Compensation Committee of the board of directors of the General Partner granted awards of phantom units and associated DERs under the LTIP to certain employees and non-employee directors of the General Partner. The phantom units granted will cliff vest on December 31, 2009 and become payable on a one-for-one basis in common units of the Partnership (or cash equivalent) upon the achievement of certain performance goals over the vesting period. The DERs that were granted in tandem with the phantom units will vest and become payable in cash simultaneously with the vesting of the phantom units. Any phantom units and associated DERs that have not vested as of the end of the cliff vesting period will be forfeited. The Partnership currently intends and reasonably expects to issue and deliver the common units upon vesting.

SFAS No. 123(R), “Share-Based Payment,” 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 Partnership’s award at the August 14, 2007 grant date approximated the fair value of the Partnership’s common unit at that date.

SFAS No. 123(R) requires compensation cost for an award of share-based employee compensation classified as equity, as is the case of the Partnership’s award, to be recognized over the requisite service period. The requisite service period for this award is from August 14, 2007, the grant date, through December 31, 2009, the vesting date. The Partnership will recognize as compensation expense 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 SFAS No. 123(R), the Partnership estimated forfeitures at the time of grant. Such estimates, which were based on the Partnership’s service and performance history, are revised, if necessary, in subsequent periods if actual forfeitures differ from estimates.

With respect to these awards, the Partnership recorded compensation expenses of approximately $0.2 million for each of the three months ended June 30, 2009 and 2008, and $0.4 million for each of the six months ended June 30, 2009 and 2008, which are included in selling, general and administrative expenses in the accompanying consolidated statements of operations. The total compensation cost related to the non-vested awards not yet recognized at June 30, 2009 is approximately $0.4 million and is expected to be recognized ratably over the remaining requisite service period.

Three-Year Phantom Units

On December 31, 2008, the Compensation Committee of the board of directors of the General Partner granted 99,700 phantom units to a named executive officer, including a contingent right to receive an amount in cash equal to the number of phantom units multiplied by the cash distribution per common unit made by the Partnership from time to time during the period the phantom units are outstanding. The phantom units, which are subject to graded vesting, will vest in six equal installments on June 30 and December 31 of each year commencing June 30, 2009. Compensation expense related to these phantom units is recognized using the accelerated attribution method. The Partnership recorded compensation expense related to this phantom unit award of approximately $0.2 million and $0.4 million for the three and six months ended June 30, 2009, respectively, which is included in selling, general and administrative expenses in the accompanying consolidated statements of operations. The total compensation cost related to the non-vested awards not yet recognized at June 30, 2009 is approximately $0.7 million and is expected to be recognized over the remaining three-year requisite service period. On June 30, 2009, 16,617 common units vested under this award and were distributed to the named executive officer. In addition, in July 2009, the Partnership paid a cash distribution related to these units of approximately $8,000.

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Note 12. Long-Term Incentive Plan (continued)

Five-Year Phantom Units

On February 5, 2009, the Compensation Committee of the board of directors of the General Partner granted awards of 277,777 phantom units under the LTIP to certain employees of the General Partner. The phantom units will vest and become payable on a one-for-one basis in common units of the Partnership (and/or cash in lieu thereof) on December 31, 2013 (or potentially sooner as described below), subject in each case to continued employment of the respective employee and subject to a performance goal for the phantom units granted to one of the recipients. Any phantom units that have not vested as of the end of the five year cliff vesting period will be forfeited.

All or a portion of the phantom units granted to the employees may vest earlier than December 31, 2013 if the Average Unit Price (as defined below) equals or exceeds specified target prices during specified periods. Specifically, if the Average Unit Price equals or exceeds: (i) $21.00 at any time prior to December 31, 2013, then 25% of the phantom units will automatically vest; (ii) $27.00 at any time during the period from February 5, 2011 through December 31, 2013, then an additional 25% of the phantom units will automatically vest; and (iii) $34.00 at any time during the period from June 5, 2012 through December 31, 2013, then all of the remaining phantom units will automatically vest. “Average Unit Price” means the average closing price of the Partnership’s common unit for any 10-consecutive trading day period.

The fair value of the Partnership’s award at the February 5, 2009 grant date approximated the fair value of the Partnership’s common unit at that date, reduced by the present value of the distributions stream on the equivalent number of common units over the derived service period. Compensation cost is recognized ratably over the derived service period which was determined for each tranche using the Monte Carlo simulation model. The derived service period of the award was assessed using expected volatility which was estimated based on historical volatility of the Partnership’s units. The Partnership recorded compensation expense related to this phantom units award of approximately $28,000 and $0.1 million for the three and six months ended June 30, 2009, respectively, which is included in selling, general and administrative expenses in the accompanying consolidated statements of operations. The total compensation cost related to the non-vested awards not yet recognized at June 30, 2009 is approximately $0.9 million and is expected to be recognized ratably over the remaining derived service periods.

Repurchase Program

In May 2009, the board of directors of the General Partner authorized the repurchase of the Partnership’s common units (the “Repurchase Program”) for the purpose of assisting it in meeting the General Partner’s anticipated obligations to deliver common units under the LTIP and meeting the General Partner’s obligations under existing employment agreements and other employment related obligations of the General Partner (collectively, the “General Partner’s Obligations”). The Partnership is authorized to spend up to $6.6 million to acquire up to 445,000 of its common units in the aggregate, over an extended period of time, consistent with the General Partner’s Obligations. Common units of the Partnership may be repurchased from time to time in open market transactions, including block purchases, or in privately negotiated transactions. Such authorized unit repurchases may be modified, suspended or terminated at any time, and are subject to price, economic and market conditions, applicable legal requirements and available liquidity. As of June 30, 2009, the General Partner repurchased 76,975 common units pursuant to the Repurchase Program for approximately $1.4 million, of which 16,617 common units vested and were distributed (see “Three-Year Phantom Units” above).

At June 30, 2009, common units outstanding excluded 60,358 common units (76,975 common units purchased less 16,617 common units vested and distributed) held on behalf of the Partnership pursuant to its Repurchase Program and for future satisfaction of the General Partner’s Obligations. As of June 30, 2009, 60,358 of the common units purchased under the Repurchase Program had not been distributed.

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Note 12. Long-Term Incentive Plan (continued)

Status of Non-Vested Units

The following table presents a summary of the status of the non-vested units as of June 30, 2009:

	Number of Non-vested Units		Weighted Average Grant Date Fair Value
Outstanding non-vested units at January 1, 2009	162,320		$	18.13
Granted	277,777		3.73
Vested	(16,617	)	11.30
Forfeited	—		—
Outstanding non-vested units at June 30, 2009	423,480		$	8.95

Note 13. Fair Value Measurements

SFAS No. 157, “Fair Value Measurements” (“SFAS No. 157”), defines fair value 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.

SFAS No. 157 establishes 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, 2009 (in thousands):

	Fair Value
	June 30,			Fair Value Measurements Using
	2009			Level 1			Level 2			Level 3
Assets:
Hedged inventories	$	347,668		$	—		$	347,668		$	—
Fair value of forward fixed price contracts	8,598			—			8,598			—
Swap agreements and options	2,528			711			1,817			—
Total assets	$	358,794		$	711		$	358,083		$	—

Liabilities:
Obligations on forward fixed price contracts	$	(14,300	)	$	—		$	(14,300	)	$	—
Swap agreements and option contracts	(5,357		)	(157		)	(5,200		)	—
Interest rate collars	(7,431		)	—			(7,431		)	—
Total liabilities	$	(27,088	)	$	(157	)	$	(26,931	)	$	—

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Note 13. Fair Value Measurements (continued)

For assets and liabilities measured on a non-recurring basis during the period, SFAS No. 157 requires quantitative disclosures about the fair value measurements separately for each major category. During the quarter ended June 30, 2009, the Partnership did not remeasure assets or liabilities at fair value on a non-recurring basis.

Financial Instruments

The fair value of the Partnership’s financial instruments approximated the carrying value as of June 30, 2009 and December 31, 2008, in each case due to the short-term and the variable interest rate nature of the financial instruments.

Note 14. Income Taxes

The following table presents a reconciliation of the difference between the statutory federal income tax rate and the effective income tax rate for the periods presented:

	Three Months Ended June 30,				Six Months Ended June 30,
	2009		2008		2009		2008
Federal statutory income tax rate	34.0	%	34.0	%	34.0	%	34.0	%
State income tax rate, net of federal tax benefit	6.4	%	6.4	%	6.4	%	6.4	%
Partnership income not subject to tax	(27.1	)%	(54.0	)%	(36.2	)%	(36.5	)%
Effective income tax rate	13.3	%	(13.6	)%	4.2	%	3.9	%

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 in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2008 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.

Note 16. Recent Accounting Pronouncements

In September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 157. This statement defines fair value, establishes guidelines for measuring fair value and requires additional disclosures regarding fair value measurements. SFAS No. 157 applies only to fair value measurements currently required or permitted by other accounting standards and is expected to increase the consistency of those measurements. The Partnership adopted SFAS No. 157 on January 1, 2008 for its financial assets and liabilities measured at fair value on a recurring basis and on January 1, 2009 for its non-financial assets and non-financial liabilities measured at fair value on a non-recurring basis which did not have a material impact on its consolidated financial statements. See Note 13.

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Note 16. Recent Accounting Pronouncements (continued)

In December 2007, the FASB issued SFAS No. 141 (Revised 2007), “Business Combinations” (“SFAS No. 141(R)”), which retains the fundamental requirements of the original pronouncement requiring that the purchase method be used for all business combinations. SFAS No. 141(R) defines the acquirer as the entity that obtains control of one or more businesses in the business combination, establishes the acquisition date as the date that the acquirer achieves control and requires the acquirer to recognize the assets acquired, liabilities assumed and any noncontrolling interest at their fair values as of the acquisition date. SFAS No. 141(R) also requires that acquisition-related costs be recognized separately from the acquisition. SFAS No. 141(R) applies prospectively to business combinations for which the acquisition date occurs in fiscal years beginning after December 15, 2008. The Partnership adopted SFAS No. 141(R) on January 1, 2009 which did not have a material impact on its consolidated financial statements.

In March 2008, the FASB issued SFAS No. 161 which enhances the requirements under SFAS No. 133. and requires enhanced disclosures about an entity’s derivatives and hedging activities and how they affect an entity’s financial position, financial performance and cash flows. The Partnership adopted SFAS No. 161 on January 1, 2009. See Note 5.

In March 2008, the EITF approved consensus on EITF Issue No. 07-04, which specifies the treatment of earnings per unit calculations when incentive distributions rights exist in master limited partnerships. Under EITF 07-04, when earnings exceed cash distributions, undistributed earnings are to be allocated to the general partner, limited partners and holders of the incentive distribution rights based on the distribution formula for available cash set forth in the partnership agreement. Conversely, when cash distributions exceed earnings, net income (or loss) would be reduced (or increased) by distributions to the general partner, limited partners and holders of incentive distribution rights. The excess of distributions over earnings would be allocated to the general partner and limited partners based on their respective sharing of losses set forth in the partnership agreement. EITF 07-04 is effective for fiscal years and interim periods beginning after December 15, 2008 and is applied retrospectively. The Partnership adopted EITF 07-04 on January 1, 2009. See Note 2.

In April 2008, the FASB issued FASB Staff Position (“FSP”) FAS 142-3, “Determination of the Useful Life of Intangible Assets” (“FSP FAS 142-3”). FSP FAS 142-3 amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under FASB Statement No. 142, “Goodwill and Other Intangible Assets” (“SFAS No. 142”). The objective of FSP FAS 142-3 is to improve the consistency between the useful life of a recognized intangible asset under SFAS No. 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS No. 141(R) and other GAAP. FSP FAS 142-3 is effective for financial statements issued for fiscal years beginning after December 15, 2008 and interim periods within those years. The Partnership adopted FSP FAS 142-3 on January 1, 2009 which did not have a material impact on its consolidated financial statements.

In June 2008, the FASB issued FSP EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (“FSP EITF 03-6-1”). FSP EITF 03-6-1 states that unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities (as defined in EITF 03-06) and, therefore, should be included in the computation of earnings per share pursuant to the two-class method. However, the award would not be considered a participating security if the holder forfeits the right to receive dividends or dividend equivalents in the event that the award does not vest. FSP EITF 03-6-1 is effective for financial statements issued for fiscal years beginning after December 15, 2008 and interim periods within those years. Upon adoption, FSP EITF 03-6-1 requires that all prior-period earnings per share data presented be adjusted retrospectively. The Partnership adopted FSP EITF 03-6-1 on January 1, 2009 which did not have a material impact on its consolidated financial statements.

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Note 16. Recent Accounting Pronouncements (continued)

In September 2008, the FASB issued EITF 08-05, “Issuer’s Accounting for Liabilities Measured at Fair Value with a Third Party Credit Enhancement” (“EITF 08-05”), which provides guidelines for the determination of the unit of accounting for a liability issued with an inseparable third-party credit enhancement when it is measured or disclosed at fair value on a recurring basis. The effect of the credit enhancement is to be excluded in the fair value measurement of the liability, and entities are required to disclose the existence of the inseparable third-party credit enhancement on the issued liability. EITF 08-05 is effective on a prospective basis beginning in the first reporting period on or after December 15, 2008, with the effect of initial application included in the change in fair value of the liability in the period of adoption. The Partnership adopted EITF 08-05 on January 1, 2009 which did not have a material impact on its consolidated financial statements.

In April 2009, the FASB issued FSP FAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments” (“FSP FAS 107-1 and APB 28-1”). This FSP amends SFAS No. 107, “Disclosures about Fair Value of Financial Instruments,” and requires disclosures about fair value of financial instruments for interim reporting periods of publicly traded companies as well as in annual financial statements. This FSP also amends APB Opinion No. 28, “Interim Financial Reporting,” which requires those disclosures in summarized financial information at interim reporting periods. This FSP is effective for interim reporting periods ending after June 15, 2009. The adoption of FSP FAS 107-1 and APB28-1 for the period ended June 30, 2009, did not have a material impact on the Partnership’s consolidated financial statements. See Note 13.

In April 2009, the FASB issued FSP FAS 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly” (“FSP FAS 157-4”). This FSP provides guidance related to: (1) estimating fair value when the volume and level of activity for an asset or liability have significantly decreased in relation to normal market activity for the asset or liability, and (2) circumstances that may indicate that a transaction is not orderly (i.e., forced liquidation or distressed sale). This FSP is effective prospectively for interim and annual reporting periods ending after June 15, 2009. The adoption of FSP FAS 157-4 did not have a material impact on the Partnership’s consolidated financial statements.

In May 2009, the FASB issued SFAS No. 165, “Subsequent Events” (“SFAS No. 165”), which establishes general standards of accounting and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. This statement requires entities to disclose the date through which they have evaluated subsequent events and whether the date corresponds with the release of their financial statements. SFAS No. 165 is effective for interim and annual periods ending after June 15, 2009. The Partnership adopted SFAS No. 165 as of June 30, 2009 which did not have an impact on its consolidated financial statements. See Note 17.

In June 2009, the FASB issued SFAS No. 168, “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles” (“SFAS No. 168”). SFAS No. 168 will become the single source of authoritative nongovernmental U.S. GAAP, superseding existing FASB, American Institute of Certified Public Accountants, EITF and related accounting literature. SFAS No. 168 reorganizes the thousands of GAAP pronouncements into roughly 90 accounting topics and displays them using a consistent structure. Also included is relevant SEC guidance organized using the same topical structure in separate sections. SFAS No. 168 will be effective for financial statements issued for reporting periods that end after September 15, 2009. The Partnership believes SFAS No. 168 will have an impact on its consolidated financial statements as all future references to authoritative accounting literature will be references in accordance with SFAS No. 168.

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(Unaudited)

Note 17. Subsequent Events

The Partnership evaluated all events or transactions that occurred through August 7, 2009, the date the Partnership issued its financial statements. Except as described below, no material subsequent events have occurred since June 30, 2009 that required recognition or disclosure in the accompanying financial statements.

On July 23, 2009, the board of directors of the General Partner declared a quarterly cash distribution of $0.4875 per unit ($1.95 per unit on an annualized basis) for the period from April 1, 2009 through June 30, 2009. On August 14, 2009, the Partnership will pay this cash distribution to its common and subordinated unitholders of record as of the close of business August 5, 2009.

The General Partner repurchased an additional 28,025 common units pursuant to the Repurchase Program from July 1, 2009 through July 10, 2009.

On August 5, 2009, Global Companies LLC (“Global”), a wholly owned subsidiary of the Partnership, entered into a Purchase and Sale Agreement (the “Purchase Agreement”) with Warex Terminals Corporation (“Warex”), a subsidiary of Warren Equities, Inc., pursuant to which Global agreed to acquire three refined products terminals from Warex for a total purchase price of $47.5 million (the “Terminals Acquisition”). The terminals, located in Newburgh, New York, have combined gasoline and distillate storage capacity of 950,000 barrels. The Terminals Acquisition, which is expected to close in the fourth quarter of 2009, is subject to the receipt of certain regulatory approvals and various other customary closing conditions. Warex is also entering into a long-term throughput contract with Global to use the terminals upon closing of the Terminals Acquisition.

As of August 5, 2009, Global Energy Marketing LLC (“GEM”) entered into a Joinder Agreement with Bank of America, N.A., as Administrative Agent and L/C Issuer, Global Operating LLC, Global Companies LLC, Global Montello Group Corp., Glen Hes Corp. and Chelsea Sandwich LLC, as borrowers, and the Partnership and the General Partner, as guarantors, which agreement joins GEM as a party to and an additional guarantor under the Partnership’s Credit Agreement.

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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

This Quarterly Report on Form 10-Q contains certain forward-looking statements within the meaning of the federal securities laws. These forward-looking statements are identified as any statements that do not relate strictly to historical or current facts and can generally be identified by the use of forward-looking terminology including “may,” “believe,” “expect,” “anticipate,” “estimate,” “continue” or other similar words. Such statements may discuss future expectations for, or contain projections of, results of operations, financial condition or our ability to make distributions to unitholders or state other forward-looking information. Forward-looking statements are not guarantees of performance. Although we believe these forward-looking statements are based on reasonable assumptions, statements made regarding future results are subject to a number of assumptions, uncertainties and risks, many of which are beyond our control, which may cause future results to be materially different from the results stated or implied in this document. These risks and uncertainties include, among other things:

· 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 refined petroleum products in the areas served by our storage facilities would 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 which conversions could have an adverse effect on our financial condition, results of operations and cash available for distribution to our unitholders.

· Warmer weather conditions could adversely affect our financial condition, results of operations and cash available for distribution to our unitholders.

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

· Our results of operations are influenced by the overall forward market for refined petroleum products, and increases and/or decreases in the prices of refined petroleum products may 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 activities.

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

· The condition of credit markets may adversely affect our liquidity.

· Due to our lack of asset and geographic diversification, adverse developments in the terminals that we use or in our operating areas could reduce our ability to make distributions to our unitholders.

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

· 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 initially to remove our general partner without its consent, which could lower the trading price of our common units.

· Unitholders may be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.

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Additional information about risks and uncertainties that could cause actual results to differ materially from forward-looking statements is contained in Part I, Item 1A, “Risk Factors,” in our Annual Report on Form 10-K for the year ended December 31, 2008 and Part II, Item 1A, “Risk Factors,” in this Quarterly Report on Form 10-Q.

All forward-looking statements included in this 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. The forward-looking statements speak only as of the date made, other than as required by law, and we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

Overview

General

We own, control or have access to one of the largest terminal networks of refined petroleum products in Massachusetts, Maine, Connecticut, Vermont, New Hampshire, Rhode Island, New York, New Jersey and Pennsylvania (collectively, the “Northeast”). We are one of the largest wholesale distributors of gasoline, distillates (such as home heating oil, diesel and kerosene) and residual oil to wholesalers, retailers and commercial customers in the Northeast. For the three and six months ended June 30, 2009, we sold approximately $1.2 billion and $2.8 billion, respectively, of refined petroleum products and small amounts of natural gas.

We purchase our refined petroleum products primarily from domestic and foreign refiners (wholesalers), traders and producers and sell these products in two segments, Wholesale and Commercial. Like most independent marketers of refined petroleum products, we base our pricing on spot physical prices and routinely use the NYMEX or other derivatives to hedge our commodity risk inherent in buying and selling energy commodities. Through the use of regulated exchanges or derivatives, we maintain a position that is substantially balanced between purchased volumes and sales volumes or future delivery obligations. We earn a margin by selling the product for physical delivery to third parties.

Products and Operational Structure

Our products include gasoline, distillates and residual oil. We sell gasoline to unbranded retail gasoline stations and other resellers of transportation fuels. The distillates we sell are used primarily for fuel for trucks and off-road construction equipment and for space heating of residential and commercial buildings. We sell 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 have increased our sales in the non-weather sensitive components of our business, such as transportation fuels; however, we are still subject to the impact that warmer weather conditions may have on our home heating oil and residual oil sales.

Our business is divided into two segments:

· Wholesale. This segment includes sales of gasoline, distillates and residual oil to unbranded retail gasoline stations and other resellers of transportation fuels, home heating oil retailers and wholesale distributors.

· Commercial. This segment includes sales and deliveries of unbranded gasoline, distillates, residual oil and small amounts of natural gas to customers in the public sector and to large commercial and industrial customers, primarily either through a competitive bidding process or through contracts of various terms. This segment also purchases, custom blends, sells and delivers bunker fuel and diesel to cruise ships, bulk carriers and fishing fleets generally by barges.

Our business activities are substantially comprised of purchasing, storing, terminalling and selling refined petroleum products. In a contango market (when product prices for future deliveries are higher than for current deliveries), 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 a backwardated market (when product prices for future deliveries are lower than current deliveries), we attempt to minimize our inventories to reduce commodity risk and maintain or increase net product margins. See Part I, Item 1A, “Risk Factors,” in our Annual Report on Form 10-K for the year ended December 31, 2008 for additional information related to commodity risk.

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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:

· The condition of credit markets may adversely affect our liquidity. During the past year, world financial markets experienced a severe reduction in the availability of credit. Although we have not been negatively impacted by this condition in the short-term, it is difficult to predict its impact on us in future quarters. Possible negative impacts 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 commit substantial resources to pursuing acquisitions, though 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 of terminalling, storage and/or marketing assets and related businesses. In an effort to prudently and economically leverage our asset base, knowledge base and skill sets, management pursues businesses that are closely related to or significantly intertwined with our existing lines of business. Our growth largely depends on our ability to make accretive acquisitions. 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 acquisition candidates or negotiate acceptable purchase contracts; (2) we are unable to raise financing for such acquisitions on economically acceptable terms; or (3) we are outbid by competitors. In addition, we may consummate acquisitions 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 acquisition efforts will be successful or that any such acquisition will be completed on terms that are favorable to us.

· Our financial results are generally better in the first and fourth 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 these winter months. Therefore, our results of operations for the first and fourth calendar quarters are generally better than for the second and third quarters. With lower cash flow during the second and third calendar quarters, we may be required to borrow money in order to maintain current levels of distributions to our unitholders.

· 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, 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. Residential users of home heating oil may also convert to natural gas. Such switching or conversion could have an adverse effect on our results of operations and financial condition.

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· Our financial condition and results of operations are influenced by the overall forward market for refined petroleum products, and increases and/or decreases in the prices of refined petroleum products may adversely impact the amount of borrowing available for working capital under our credit agreement, which credit agreement has borrowing base limitations and advance rates. Results from our supply, marketing and terminalling operations are influenced by prices for refined petroleum products, pricing volatility and the market for such products. When prices for refined petroleum products 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 to our customers, resulting in lower margins for us which could adversely affect our results of operation. Lastly, higher prices for refined petroleum prices 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. In addition, when prices for refined petroleum products 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 refined petroleum products at the then lower spot and/or retail market price. Furthermore, lower prices for refined petroleum products may diminish the amount of borrowings available for working capital under our working capital revolving credit facility as a result of borrowing base limitations.

· 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. 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) selling, general and administrative expenses (“SG&A”), (4) operating expenses, (5) degree days, (6) net income per diluted limited partner unit, (7) earnings before interest, taxes, depreciation and amortization (“EBITDA”) and (8) distributable cash flow.

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 include sales of unbranded gasoline, distillates, residual oil and natural gas. Product costs include the cost of acquiring the refined petroleum products and natural gas that we sell and all associated costs including shipping and handling costs to bring such products to the point of sale. 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 as an alternative to net income, operating income, cash flow from operations, or any other measure of financial performance presented in accordance with GAAP. In addition, our 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 depreciation expense allocated to cost of sales. Sales include sales of unbranded gasoline, distillates, residual oil and natural gas. Product costs include the cost of acquiring the refined petroleum products and natural gas that we sell and all associated costs to bring such products to the point of sale.

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Selling, General and Administrative Expenses

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

Degree Day

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

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, divided by the weighted average number of outstanding diluted common and subordinated units, or limited partner units, during the period.

EBITDA

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

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

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

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

· our operating performance and return on invested capital as compared to those of other companies in the wholesale, marketing and distribution of refined petroleum products, 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.

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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 less our maintenance capital expenditures. Specifically, this financial measure indicates to investors whether or not we have generated sufficient cash flow on a current or historic level that can sustain or support an increase in our quarterly cash distribution. Distributable cash flow is a quantitative standard used by the investment community with respect to publicly traded partnerships. Distributable cash flow should not be considered as an alternative to net income, 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.

Three and six months ended June 30, 2009 and 2008

During the three and six months ended June 30, 2009, we experienced the following events:

· Refined petroleum product prices dramatically declined compared to the same periods in 2008 which we believe contributed to lower revenues and lower financing costs as a result of decreased borrowings to finance inventory.

· Temperatures for the three months ended June 30, 2009 were 9% warmer than normal and 1% warmer than the second quarter of 2008. Temperatures for the six months ended June 30, 2009 were 1% colder than normal and 7% colder than the same period in 2008.

· We increased our reserve for credit losses by expensing approximately $0.5 million and $1.1 million for the three and six months ended June 30, 2009, respectively.

· We believe heating oil conservation continued during the three and six months ended June 30, 2009 even though prices declined.

· Additionally, we experienced the following events during the first quarter of 2008 that we did not experience during the three and six months ended June 30, 2009:

· Adverse market conditions in our markets, including volatility and backwardation, led to lower margins and intensified competition from other wholesalers.

· The opportunistic conversion of certain gasoline markets to ethanol put us in a temporarily disadvantaged competitive position while our terminal infrastructure was being converted.

· Temporary logistical supply issues related to rail capacity adversely affected the performance of our Burlington, Vermont facility.

The following table provides the percentage decreases in refined petroleum product and natural gas prices at the end of the first two quarters in 2009 as compared to each comparable quarter in 2008:

Period:	Heating Oil $ per gallon(1)			Gasoline $ per gallon(1)			Residual Oil $ per barrel(2)			Natural Gas $ per barrel equivalent(3)
At March 31, 2008	$	3.05		$	2.62		$	72.75		$	64.38
At March 31, 2009	$	1.34		$	1.40		$	40.00		$	25.96
Change	(56		)%	(47		)%	(45		)%	(60		)%

At June 30, 2008	$	3.90		$	3.50		$	111.30		$	86.37
At June 30, 2009	$	1.72		$	1.90		$	62.50		$	26.15
Change	(56		)%	(46		)%	(44		)%	(70		)%

(1) Source: New York Mercantile Exchange

(2) Source: Platts Oilgram Price Report

(3) Source: Platts Gas Daily Report

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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,
	2009			2008			2009			2008
Net income (loss)	$	978		$	(1,254	)	$	19,841		$	7,365

Net income (loss) per diluted limited partner unit (1)	$	0.07		$	(0.10	)	$	1.46		$	0.55

EBITDA (2)	$	8,586		$	6,793		$	35,952		$	25,269

Distributable cash flow (3)	$	3,288		$	2,248		$	25,284		$	14,057

Wholesale Segment:
Volume (gallons)	682,771			688,825			1,721,390			1,691,148
Sales
Distillates	$	405,060		$	883,577		$	1,411,676		$	2,486,987
Gasoline	720,330			1,283,676			1,221,989			2,258,744
Residual oil	5,853			25,220			17,343			43,577
Total	$	1,131,243		$	2,192,473		$	2,651,008		$	4,789,308
Net product margin (4)
Distillates	$	13,477		$	9,329		$	47,330		$	32,421
Gasoline	12,127			10,424			23,913			18,968
Residual oil	2,294			3,234			5,114			7,130
Total	$	27,898		$	22,987		$	76,357		$	58,519
Commercial Segment:
Volume (gallons)	45,533			41,768			121,261			103,579
Sales	$	69,906		$	105,236		$	183,096		$	229,393
Net product margin (4)	$	2,596		$	2,323		$	7,524		$	4,929
Combined sales and net product margin:
Sales	$	1,201,149		$	2,297,709		$	2,834,104		$	5,018,701
Net product margin (4)	$	30,494		$	25,310		$	83,881		$	63,448
Depreciation allocated to cost of sales	2,705			2,637			5,378			5,159
Combined gross profit	$	27,789		$	22,673		$	78,503		$	58,289

Weather conditions:
Normal heating degree days	784			784			3,654			3,685
Actual heating degree days	716			721			3,693			3,449
Variance from normal heating degree days	(9		)%	(8		)%	1		%	(6		)%
Variance from prior period actual heating degree days	(1		)%	(12		)%	7		%	(8		)%

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

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

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

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

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2009			2008			2009		2008
Reconciliation of net income (loss) to EBITDA:
Net income (loss)	$	978		$	(1,254	)	$	19,841	$	7,365
Depreciation and amortization and amortization of deferred financing fees	4,036			3,810			8,038		7,492
Interest expense	3,422			4,087			7,198		10,117
Income tax expense	150			150			875		295
EBITDA	$	8,586		$	6,793		$	35,952	$	25,269

Reconciliation of cash flow (used in) provided by operating activities to EBITDA:
Cash flow (used in) provided by operating activities	$	(91,049	)	$	(103,790	)	$	20,181	$	(5,973	)
Net changes in operating assets and liabilities and certain non-cash items	96,063			106,346			7,698		20,830
Interest expense	3,422			4,087			7,198		10,117
Income tax expense	150			150			875		295
EBITDA	$	8,586		$	6,793		$	35,952	$	25,269

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,
	2009			2008			2009			2008
Reconciliation of net income (loss) to distributable cash flow:
Net income (loss)	$	978		$	(1,254	)	$	19,841		$	7,365
Depreciation and amortization and amortization of deferred financing fees	4,036			3,810			8,038			7,492
Maintenance capital expenditures	(1,726		)	(308		)	(2,595		)	(800		)
Distributable cash flow	$	3,288		$	2,248		$	25,284		$	14,057

Reconciliation of cash flow (used in) provided by operating activities to distributable cash flow:
Cash flow (used in) provided by operating activities	$	(91,049	)	$	(103,790	)	$	20,181		$	(5,973	)
Net changes in operating assets and liabilities and certain non-cash items	96,063			106,346			7,698			20,830
Maintenance capital expenditures	(1,726		)	(308		)	(2,595		)	(800		)
Distributable cash flow	$	3,288		$	2,248		$	25,284		$	14,057

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Consolidated Results

Our total sales for the second quarter of 2009 decreased by $1,096.6 million, or 48%, to $1,201.1 million compared to $2,297.7 million for the same period in 2008. The decrease was driven primarily by significantly lower refined petroleum product and natural gas prices for the three months ended June 30, 2009 compared to the same period in 2008. Our aggregate volume of product sold decreased by approximately 2 million gallons to 729 million gallons. The decrease in volume primarily includes decreases of approximately 7 million gallons and 9 million gallons in distillates and residual oil, respectively, attributable to warmer temperatures during the second quarter of 2009 compared to the same period in 2008. The decrease in volume sold was offset by an increase of 10 million gallons in gasoline.

The number of actual heating degree days decreased by 1% to 716 for the three months ended June 30, 2009 compared with 721 for the same period in 2008. Our gross profit for the second quarter of 2009 was $27.8 million, an increase of $5.1 million, or 22%, compared to $22.7 million for the same period in 2008. The increase was primarily due to higher net product margins in distillates and gasoline.

Our total sales for the six months ended June 30, 2009 decreased by $2,814.6 million, or 44%, to $2,834.1 million compared to $5,018.7 million for the same period in 2008. The decrease was driven primarily by significantly lower refined petroleum product and natural gas prices for the six months ended June 30, 2009 compared to the same period in 2008. Our aggregate volume of product sold increased by approximately 48 million gallons, or 3%, to 1,843 million gallons. The increase in volume primarily includes increases of approximately 36 million gallons in distillates and 9 million gallons in gasoline.

The number of actual heating degree days increased 7% to 3,693 for the six months ended June 30, 2009 compared with 3,449 for the same period in 2008. Our gross profit for the six months ended June 30, 2009 was $78.5 million, an increase of $20.2 million, or 35%, compared to $58.3 million for the same period in 2008. The increase was primarily due to higher net product margins in distillates and gasoline.

Wholesale Segment

Distillates. Wholesale distillate sales for the three months ended June 30, 2009 were $405.1 million compared to $883.6 million for the three months ended June 30, 2008. During the first six months of 2009, wholesale distillate sales were $1,411.7 million compared to $2,487.0 million for the same period in 2008. The decreases of $478.5 million, or 54%, and $1,075.3 million, or 43%, for the three and six months ended June 30, 2009, respectively, were due to the significantly lower refined petroleum product prices.

We experienced an 8 million gallon, or 3%, decrease in distillate volume sold for the second quarter of 2009 compared to the same period in 2008 which was attributed to warmer temperatures and a 27 million gallon, or 3%, increase in distillate volume sold for the six months ended June 30, 2009 compared to the same period in 2008 which was attributed to colder temperatures.

Our net product margin from distillate sales increased by $4.2 million, or 45%, to $13.5 million for the three months ended June 30, 2009 and by $14.9 million, or 46% to $47.3 million for the six months ended June 30, 2009 compared to the same periods in 2008, primarily attributable to better unit margins and, for the six months ended June 30, 2009 compared to the same period in 2008, an increase in volume.

Gasoline. Wholesale gasoline sales for the three months ended June 30, 2009 were $720.3 million compared to $1,283.7 million for the same period in 2008. During the first six months of 2009, wholesale gasoline sales were $1,222.0 million compared to $2,258.7 million for the same period in 2008. The decreases of $563.4 million, or 44%, and $1,036.7 million, or 46%, were due primarily to significantly lower gasoline prices compared to the prior periods.

Our net product margin from gasoline sales increased by $1.7 million to $12.1 million for the three months ended June 30, 2009 and by $4.9 million to $23.9 million for the six months ended June 30, 2009 compared to the same periods in 2008. These increases were primarily attributable to better unit margins and increases in gasoline volume for the three and six months ended June 30, 2009 compared to the same periods in 2008.

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Residual Oil. Wholesale residual oil sales for the three months ended June 30, 2009 were $5.8 million compared to $25.2 million for the three months ended June 30, 2008. During the first six months of 2009, residual oil sales were $17.3 million compared to $43.6 million for the same period in 2008. The decreases of $19.4 million, or 77%, and $26.3 million, or 60%, were primarily due to significantly lower refined petroleum product prices compared to the prior periods and decreases in volume sold of 8 million and 6 million for the three and six months ended June 30, 2009, respectively, compared to the same periods in 2008. The decreases in volume sold were the result of continued conservation, current economic conditions and conversion and fuel switching related to the decrease in natural gas prices compared to residual oil prices.

Our net product margin contribution from residual oil sales decreased by $0.9 million, or 29%, to $2.3 million for the three months ended June 30, 2009 and by $2.0 million, or 28%, to $5.1 million for the six months ended June 30, 2009 compared to the same periods in 2008 due to intensified competition in the marketplace.

Commercial Segment

In our Commercial segment, residual oil accounted for approximately 55% and 63% of total commercial volume sold for the three months ended June 30, 2009 and 2008, respectively, and approximately 63% and 68% for the six months ended June 30, 2009 and 2008, respectively. Distillates, gasoline and natural gas accounted for the remainder of the total volume sold.

Commercial residual oil sales for the quarter ended June 30, 2009 decreased by 40% compared to the same period in 2008. For the six months ended June 30, 2009, residual oil sales decreased 29% compared to the same period in 2008. We attribute the decreases in sales to the competitive pricing from natural gas, reductions in production by certain industry participants in our markets and decreases in residual oil volume sold.

Selling, General and Administrative Expenses

SG&A expenses increased by $3.1 million, or 30%, to $13.3 million for the three months ended June 30, 2009 compared to $10.2 million for the same period in 2008. The increase was primarily due to increases of $0.5 million in bad debt accrual due to some credit strain on our customer base, $0.4 million in employee benefits, $0.3 million in professional fees, $0.2 million in costs associated with the expansion of our natural gas operations, $0.2 million in compensation cost on our long-term incentive plan, $0.1 million in accrued bonuses, $0.1 million in bank fees and $1.3 million in various other SG&A expenses, including information systems, marketing and product promotion and diligence on expansion projects.

SG&A expenses increased by $10.1 million, or 47%, to $31.4 million for the six months ended June 30, 2009 compared to $21.3 million for the same period in 2008. The increase was primarily due to increases of $5.0 million in accrued bonuses, $1.1 million in bad debt accrual due to some credit strain on our customer base, $0.9 million in professional fees, $0.7 million in employee benefits, $0.5 million in compensation cost on our long-term incentive plan, $0.5 million in bank fees, $0.2 million in costs associated with the expansion of our natural gas operations and $1.2 million in various other SG&A expenses, including information systems, marketing and product promotion and diligence on expansion projects.

Operating Expenses

Operating expenses increased by $0.3 million, or 4%, to $9.1 million for the three months ended June 30, 2009 compared to $8.8 million for the same period in 2008. The increase was primarily due to increased costs of approximately $0.5 million related to our recently leased storage facility in Long Island, New York and $0.3 million in other operating costs, offset by $0.5 million in cost savings related to the non-renewal of the terminal lease in New Haven, Connecticut.

Operating expenses decreased by $0.2 million, or 1%, to $17.6 million for the six months ended June 30, 2009 compared to $17.8 million for the same period in 2008. The decrease was primarily due to decreases of $1.0 million in cost savings related to the non-renewal of the terminal lease in New Haven, Connecticut, offset by approximately $0.7 million related to our recently leased storage facility in Long Island, New York and $0.1 million in other operating costs.

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Interest Expense

Interest expense for the three months ended June 30, 2009 decreased by $0.7 million, or 16%, to $3.4 million compared to $4.1 million for the same period in 2008. Interest expense for the six months ended June 30, 2009 decreased by $2.9 million, or 29%, to $7.2 million compared to $10.1 million for the same period in 2008. We attribute the decreases primarily to lower average balances on our working capital credit facility from carrying lower average balances on inventories and accounts receivable due to lower refined petroleum product prices. In addition, interest rates were lower during the three and six months ended June 30, 2009 compared to the same periods in 2008. The decreases in interest expense were partially offset by an increase in the costs of borrowings commencing with the July 18, 2008 amendment to the credit agreement.

Liquidity and Capital Resources

Liquidity

Our primary liquidity needs are to fund our working capital requirements and our capital expenditures. Cash generated from operations and our working capital revolving credit facility provide our primary sources of liquidity. Working capital increased by $82.0 million to $280.6 million at June 30, 2009 compared to $198.6 million at December 31, 2008.

On February 13, 2009, we paid a cash distribution to our common and subordinated unitholders and our general partner of approximately $6.5 million for the fourth quarter of 2008 and on May 15, 2009, we paid a cash distribution to our common and subordinated unitholders and our general partner of approximately $6.5 million for the first quarter of 2009. On July 23, 2009, the board of directors of our general partner declared a quarterly cash distribution of $0.4875 per unit for the period from April 1, 2009 through June 30, 2009 ($1.95 per unit on an annualized basis) to our common and subordinated unitholders of record as of the close of business August 5, 2009. We expect to pay the cash distribution of approximately $6.5 million on August 14, 2009.

Capital Expenditures

Our terminalling operations require investments to expand, upgrade and enhance existing operations and to meet environmental and operations regulations. Our capital requirements primarily consist of maintenance capital expenditures and expansion capital expenditures. Maintenance capital expenditures represent capital expenditures to replace partially or fully depreciated assets to maintain the operating capacity of, or sales generated by, existing assets and extend their useful lives, such as expenditures required to maintain equipment reliability, tankage and pipeline integrity and safety, and to address environmental regulations. We anticipate that maintenance capital expenditures will be funded with cash generated by operations. We had approximately $2.6 million and $0.8 million in maintenance capital expenditures for the six months ended June 30, 2009 and 2008, 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 and to expand existing facilities, such as projects that increase operating capacity by increasing tankage, diversifying product availability at various terminals and adding terminals. We generally fund our expansion capital expenditures through our cash generated from operations or our acquisition and working capital revolving credit facilities or by issuing additional equity. We had approximately $3.7 million and $4.7 million in expansion capital expenditures for the six months ended June 30, 2009 and 2008, respectively, to increase our operating capacity and capabilities. Specifically, for the six months ended June 30, 2009, expansion capital expenditures consisted of approximately $2.7 million in costs related to dock expansion and bringing formerly out-of-permit tanks back online at the Albany, New York terminal, $0.8 million in additional terminal equipment at the Providence, Rhode Island terminal and $0.2 million in automation costs at our recently leased storage facility in Long Island, New York. Comparatively, for the six months ended June 30, 2008, expansion capital expenditures included $2.7 million in expenditures related to construction in process on our leased terminal in Providence, Rhode Island, $1.1 million related to conversion expenditures to handle ethanol-based gasoline and $0.9 million in other expansion capital expenditures.

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We believe that we will have 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.

Cash Flow

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

	Six Months Ended
	June 30 31,
	2009			2008
Net cash provided by (used in) provided by operating activities	$	20,181		$	(5,973	)
Net cash used in investing activities	$	(6,303	)	$	(5,510	)
Net cash (used in) provided by financing activities	$	(11,861	)	$	11,793

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

Net cash provided by operating activities was $20.2 million for the six months ended June 30, 2009 compared to net cash used in operating activities of $6.0 million for the six months ended June 30, 2008.

During the six months ended June 30, 2009, refined petroleum product and natural gas prices declined significantly compared to the same period in 2008, causing the carrying values of our accounts receivable and accounts payable for the six months ended June 30, 2009 to be less than the carrying values we experienced for the six months ended June 30, 2008. As a result, for the six months ended June 30, 2009, we had decreases of $58.8 million and $87.6 million in accounts receivable and accounts payable, respectively, while, we had decreases of $37.1 million and $40.4 million in accounts receivable and accounts payable, respectively, for the six months ended June 30, 2008.

Due to favorable market conditions, we elected to use our storage capacity to carry increased inventories of approximately $129.0 million for the six months ended June 30, 2009. Comparatively, for the six months ended June 30, 2008 when prices were higher, inventories increased by only $3.2 million for the six months ended June 30, 2008. Through the use of regulated exchanges or derivatives, we maintain a position that is substantially hedged with respect to such inventories.

The cash provided by operating activities is also reflected in the year-over-year increase in net income of $12.4 million and a $167.0 million change in the fair value of our forward fixed price contracts. For the six months ended June 30, 2009, contracts supporting our forward fixed price hedge program provided funds from the NYMEX of approximately $159.5 million while for the six months ended June 30, 2008 similar hedging activity required margin payments of approximately $7.5 million to the NYMEX due to market direction.

Net cash used in investing activities increased by $0.8 million for the six months ended June 30, 2009 compared to the same period in 2008 and included $2.6 million in maintenance capital expenditures and $3.7 million in expansion capital expenditures ($2.7 million in costs related to dock expansion and bringing formerly out-of-permit tanks back online at the Albany, New York terminal, $0.8 million in additional terminal equipment at the Providence, Rhode Island terminal and $0.2 million in automation costs at our recently leased storage facility in Long Island, New York). Comparatively, for the six months ended June 30, 2008, net cash used in investing activities included $5.5 million in total capital expenditures comprised of $0.8 million in maintenance capital expenditures and $4.7 million in expansion capital expenditures ($2.7 million related to construction in process on our leased terminal in Providence, Rhode Island, $1.1 million related to conversion expenditures to handle ethanol-based gasoline and $0.9 million in other expansion capital expenditures).

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Net cash used in financing activities was $11.9 million for the six months ended June 30, 2009 and included $13.0 million in cash distributions to our common and subordinated unitholders and our general partner, $1.3 million in the repurchases of common units held on our behalf pursuant to our Repurchase Program and for future satisfaction of our General Partner’s Obligations (as defined in Note 12 of Notes to Consolidated Financial Statements), offset by $2.5 million in net proceeds on our credit facilities. The $1.3 million in the repurchases of common units excludes approximately $0.1 million of additional funds due upon trade settlement in July 2009. Comparatively, for the six months ended June 30, 2008, net cash provided by financing activities included net proceeds from our credit facilities of $26.1 million, offset by $13.1 million in cash distributions to our common and subordinated unitholders and our general partner and $1.2 million in payments on our note payable.

Credit Agreement

We, our general partner, our operating company and our operating subsidiaries have a four-year senior secured credit agreement with total available commitments of $750.0 million. We repay amounts outstanding and reborrow funds based on our working capital requirements and, therefore, classify as a current liability the portion of the working capital revolving credit facility we expect to pay down during the course of the year. The long-term portion of the working capital revolving credit facility is the amount we expect to be outstanding during the entire year. The credit agreement will mature on April 22, 2011.

There are 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 $650.0 million; the $650.0 million includes two $50.0 million seasonal overline facilities that are available each year only during the period between September 1 and June 30;

· an $85.0 million acquisition facility to be used for funding acquisitions similar to our business line that have a purchase price of $25.0 million or less or $35.0 million or less in the aggregate in any 12-month period; and

· a $15.0 million revolving credit facility to be used for general purposes, including payment of distributions to our unitholders.

In addition, the credit agreement has an accordion feature whereby we may request on the same terms and conditions of our then existing credit agreement, provided no Event of Default (as defined in the credit agreement) then exists, an increase to: (1) the acquisition facility by up to another $50.0 million, for a total acquisition facility of up to $135.0 million; and (2) the working capital revolving credit facility by up to another $200.0 million, for a total working capital revolving credit facility of up to $850.0 million. Any such request for an increase by us must be in a minimum amount of $5.0 million, and no more than three such requests may be made for each facility. We, however, cannot provide assurance that our lending group will agree to fund any request by us for additional amounts in excess of the total available commitments of $750.0 million.

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 the credit agreement, we can borrow only up to the level of our then current borrowing base. Availability under our borrowing base may be affected by events beyond our control, such as changes in refined petroleum product prices, collection cycles, counterparty performance, advance rates and limits and deteriorating 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.

During the period from January 1, 2008 through July 20, 2008, borrowings under our working capital revolving credit, acquisition and revolving credit facilities bore interest at our option at (1) the Eurodollar rate, plus 1%, 1½% and 1½%, respectively, (2) the cost of funds rate, plus 1%, 1¾% and 1½%, respectively, or (3) the bank’s base rate. Commencing July 21, 2008, borrowings under the working capital revolving credit facility bear interest at (1) the Eurodollar rate plus 1.75% to 2.25%, (2) the cost of funds rate plus 1.75% to 2.25%, or (3) the base rate plus 0.75% to 1.25%, each depending on the pricing level provided in the credit agreement, which in turn depends upon the Combined Interest Coverage Ratio (as defined in the credit agreement). Commencing July 21, 2008, borrowings under the acquisition and revolving credit facilities bear interest at (1) the Eurodollar rate plus 2.25% to 2.75%, (2) the cost of funds rate plus 1.75% to 2.25%, or (3) the base rate plus 0.75% to 1.25%, each depending on the pricing level provided

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in the credit agreement, which in turn depends upon the Combined Interest Coverage Ratio. The average interest rate was approximately 3.8% for each of the three months ended June 30, 2009 and 2008. The average interest rates were approximately 3.8% and 4.2% for the six months ended June 30, 2009 and 2008, respectively.

We incur a letter of credit fee of 1.75% per annum for each letter of credit issued. In addition, we incur a commitment fee on the unused portion of the three facilities under the credit agreement (including the unused portion of either of the seasonal overline facilities exercised by us) equal to 0.3% to 0.375% per annum, depending on the pricing level and the Combined Interest Coverage Ratio provided in the credit agreement. We also incur a facility fee of 0.1% per annum on any unexercised seasonal overline facility during the period between September 1 and June 30 and a seasonal overline fee of $30,000 each time we elect to exercise either of the seasonal overline facilities.

As of June 30, 2009, we had total borrowings outstanding under our credit agreement of $436.0 million, including $71.2 million outstanding on our acquisition facility, and outstanding letters of credit of $54.0 million. The total remaining availability for borrowings and letters of credit at June 30, 2009 and December 31, 2008 was $260.0 million and $211.3 million, respectively.

The credit agreement imposes financial covenants that require us to maintain certain minimum working capital amounts, capital expenditure limits, a minimum EBITDA ratio, a minimum combined interest coverage ratio and a maximum leverage ratio. We were in compliance with the foregoing covenants at June 30, 2009. 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).

The credit agreement provides that in each calendar year the outstanding amount under the working capital revolving credit facility must be equal to or less than $263.0 million for a period of ten consecutive calendar days. We have complied with this provision for the year ending December 31, 2009. It is anticipated that the seasonal decrease in working capital as we exit our heating season will contribute to a decrease in borrowings outstanding under our credit agreement.

The credit agreement limits distributions to our unitholders to available cash and permits borrowings to fund such distributions only under the $15.0 million revolving credit facility. The revolving credit facility is subject to an annual “clean-down” period, requiring us to reduce the amount outstanding under the revolving credit facility to $0 for 30 consecutive calendar days in each calendar year. We have complied with this provision for the year ending December 31, 2009.

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

The lending group under the credit agreement includes the following institutions: Bank of America, N.A.; Standard Chartered Bank; JPMorgan Chase Bank, N.A.; Societe Generale; RBS Citizens, National Association; Sovereign Bank; Fortis Capital Corp.; Webster Bank National Association; KeyBank National Association; TD Bank, N.A. (f/k/a TD BankNorth, N.A.); Wells Fargo Bank, N.A.; Wachovia Bank, National Association; and Calyon New York Branch.

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.

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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. 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 and environmental and other liabilities.

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, 2008. 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 16 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 two interest rate collars to manage exposure to interest rate risk and various derivative instruments to manage exposure to commodity risk.

Interest Rate Risk

We utilize variable rate debt and are exposed to market risk due to the floating interest rates on our credit facility. Therefore, from time to time, we utilize interest rate collars to hedge interest obligations on specific and anticipated debt issuances.

During the period from January 1, 2008 through July 20, 2008, borrowings under our working capital revolving credit, acquisition credit and revolving credit facilities bore interest at our option at (1) the Eurodollar rate, plus 1%, 1½% and 1½ %, respectively, (2) the cost of funds rate, plus 1%, 1¾% and 1½ %, respectively, or (3) the bank’s base rate. Commencing July 21, 2008, borrowings under the working capital revolving credit facility bear interest at (1) the Eurodollar rate plus 1.75% to 2.25%, (2) the cost of funds rate plus 1.75% to 2.25%, or (3) the base rate plus 0.75% to 1.25%, each depending on the pricing level provided in the credit agreement, which in turn depends upon the Combined Interest Coverage Ratio (as defined in the credit agreement). Commencing July 21, 2008, borrowings under the acquisition and revolving credit facilities bear interest at (1) the Eurodollar rate plus 2.25% to 2.75%, (2) the cost of funds rate plus 1.75% to 2.25%, or (3) the base rate plus 0.75% to 1.25%, each depending on the pricing level provided in the credit agreement, which in turn depends upon the Combined Interest Coverage Ratio. The average interest rate was approximately 3.8% for each of the three months ended June 30, 2009 and 2008. The average interest rates were approximately 3.8% and 4.2% for the six months ended June 30, 2009 and 2008, respectively.

As of June 30, 2009, we had total borrowings outstanding under the credit agreement of $436.0 million. 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 $4.4 million annually, assuming, however, that our indebtedness remained constant throughout the year.

We executed two zero premium interest rate collars with major financial institutions. Each collar is designated as a cash flow hedge and accounted for under the provisions of SFAS No. 133. The first collar, which became effective on May 14, 2007 and expires on May 14, 2011, is used to hedge the variability in interest payments due to changes in the three-month LIBOR rate with respect to $100.0 million of three-month LIBOR-based borrowings. Under the first collar, we capped our exposure at a maximum three-month LIBOR rate of 5.75% and established a minimum floor rate of 3.75%. Whenever the three-month LIBOR rate is greater than the cap, we receive from the respective financial institution the difference between the cap and the current three-month LIBOR rate on the $100.0 million of three-month LIBOR-based borrowings. Conversely, whenever the three-month LIBOR rate is lower than the floor, we remit to the respective financial institution the difference between the floor and the current three-month LIBOR rate on the $100.0 million of three-month LIBOR-based borrowings. As of June 30, 2009, the three-month LIBOR rate of 0.91%

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was lower than the floor rate. As a result, in August, we will remit to the respective financial institution the difference between the floor rate and the current rate which amounted to approximately $379,000.

On September 29, 2008, we executed our second zero premium interest rate collar. The second 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 our $100.0 million one-month LIBOR-based borrowings (and subsequent refinancings thereof) due to changes in the one-month LIBOR rate. Under the second collar, we capped our exposure at a maximum one-month LIBOR rate of 5.50% and established a minimum floor rate of 2.70%. Whenever the one-month LIBOR rate is greater than the cap, we receive from the respective financial institution the difference between the cap and the current one-month LIBOR rate on the $100.0 million of one-month LIBOR-based borrowings. Conversely, whenever the one-month LIBOR rate is lower than the floor, we remit to the respective financial institution the difference between the floor and the current one-month LIBOR rate on the $100.0 million of one-month LIBOR-based borrowings. As of June 30, 2009, the one-month LIBOR rate of 0.32% was lower than the floor rate. As a result, in July 2009, we remitted to the respective financial institution the difference between the floor rate and the current rate which amounted to approximately $192,000. See Note 5 of Notes to Consolidated Financial Statements for further discussion on the interest rate collars.

Commodity Risk

We hedge our exposure to price fluctuations with respect to refined petroleum products in storage and expected purchases and sales of these commodities. The derivative instruments utilized consist primarily of futures contracts traded on the NYMEX 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, some degree of exposure to unforeseen 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 logistical issues associated with inclement weather conditions. In connection with managing these positions and maintaining a constant presence in the marketplace, both necessary for our business, we engage in a controlled trading program for up to an aggregate of 250,000 barrels of refined petroleum products at any one point in time.

We enter into futures contracts to minimize or hedge the impact of market fluctuations on our purchases and forward fixed price sales of refined petroleum products. Any hedge ineffectiveness is reflected in our results of operations. We utilize the NYMEX, which is a regulated exchange for energy products that it trades, thereby reducing potential delivery and supply risks. Generally, our practice is to close all NYMEX positions rather than to make or receive physical deliveries. With respect to other energy products, 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, 2009, 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 are shown in the table below (in thousands):

Gain (loss):

	Fair Value at June 30, 2009			Effect of 10% Price Increase
NYMEX contracts	$	(31,014	)	$	(23,255	)
Swaps, options and other, net	(2,830		)	(5,019		)
	$	(33,844	)	$	(28,274	)

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The fair values of the futures contracts are based on quoted market prices obtained from the NYMEX. 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, 2009. 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 spot 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 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 broker 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 required brokerage margin balance was $25.9 million at June 30, 2009.

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 one clearing broker, a major financial institution, 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, 2009.

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, 2009 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 in our Annual Report on Form 10-K for the year ended December 31, 2008 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.

Item 1A. Risk Factors

There have been no material changes to the Risk Factors disclosed in our Annual Report on Form 10-K for the year ended December 31, 2008.

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

Issuer Purchases of Equity Securities

The table below provides information with respect to purchases of our common units made by our general partner on our behalf during the quarter ended June 30, 2009:

				Maximum Number (or
			Total Number of	Approximate Dollar
			Units Purchased as	Value) of Units That May
	Total Number	Average	Part of Publicly	Yet Be Purchased
	Of Units	Price Paid	Announced Plans or	Under the Plans or
Period	Purchased	Per Unit	Programs(1)	Programs(1)
April 1 – April 30, 2009	—	—	—	—
May 1 – May 31, 2009	—	—	—	—
June 1 – June 30, 2009	76,975	18.21	76,975	—

(1) On May 7, 2009, the board of directors of the general partner announced that it authorized the repurchase of our common units for the purpose of assisting us in meeting the general partner’s anticipated obligations to deliver common units under our LTIP and meeting the general partner’s obligations under existing employment agreements and other employment related obligations of the general partner. We are authorized to spend up to $6.6 million to acquire up to 445,000 of our common units in the aggregate, over an extended period of time, consistent with the general partner’s obligations under the LTIP and employment agreements. Common units may be repurchased from time to time in open market transactions, including block purchases, or in privately negotiated transactions. Such authorized unit repurchases may be modified, suspended or terminated at any time, and are subject to price, economic and market conditions, applicable legal requirements and available liquidity.

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Item 6. Exhibits

3.1	—	Second Amended and Restated Agreement of Limited Partnership of Global Partners LP dated as of May 9, 2007 (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K filed on May 10, 2007).

3.2	—	Amendment No. 1 to the Second Amended and Restated Agreement of Limited Partnership of Global Partners LP dated April 14, 2008 (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K filed on April 17, 2008).

10.1	—	Joinder Agreement, dated as of August 5, 2009, among Global Energy Marketing LLC, as a new guarantor, Global Operating LLC, Global Companies LLC, Global Montello Group Corp., Glen Hes Corp. and Chelsea Sandwich LLC, as borrowers, Global Partners LP and Global GP LLC, as guarantors, and Bank of America, N.A., as Administrative Agent and L/C Issuer.

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.

† 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 7, 2009		By:	/s/ Eric Slifka
			Eric Slifka
			President and Chief Executive Officer
			(Principal Executive Officer)


Dated: August 7, 2009		By:	/s/ Thomas J. Hollister
			Thomas J. Hollister
			Chief Operating Officer and Chief Financial Officer
			(Principal Financial Officer)

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INDEX TO EXHIBITS

Exhibit Number			Description

3.1		—	Second Amended and Restated Agreement of Limited Partnership of Global Partners LP dated as of May 9, 2007 (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K filed on May 10, 2007).

3.2		—	Amendment No. 1 to the Second Amended and Restated Agreement of Limited Partnership of Global Partners LP dated April 14, 2008 (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K filed on April 17, 2008).

10.1		—	Joinder Agreement, dated as of August 5, 2009, among Global Energy Marketing LLC, as a new guarantor, Global Operating LLC, Global Companies LLC, Global Montello Group Corp., Glen Hes Corp. and Chelsea Sandwich LLC, as borrowers, Global Partners LP and Global GP LLC, as guarantors, and Bank of America, N.A., as Administrative Agent and L/C Issuer.

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.

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