Edgar Filing: GLOBAL PARTNERS LP

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-Q

(Mark One)

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

	For the quarterly period ended September30, 2011

	OR

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

	For the transition period from to

Commission file number 001-32593

Global Partners LP

(Exact name of registrant as specified in its charter)

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

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

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

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

Yes ý No o

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

Yes ý No o

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

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No ý

The issuer had 21,580,563 common units outstanding as of October 31, 2011.

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TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION

Item 1.	Financial Statements

Consolidated Balance Sheets as of September 30, 2011 and December 31, 2010

Consolidated Statements of Income for the three and nine months ended September 30, 2011 and 2010

Consolidated Statements of Cash Flows for the nine months ended September 30, 2011 and 2010

Consolidated Statements of Partners’ Equity for the nine months ended September 30, 2011

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

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Item 1. Financial Statements

GLOBAL PARTNERS LP

CONSOLIDATED BALANCE SHEETS

(In thousands, except unit data)

(Unaudited)

	September 30,			December 31,
	2011			2010
Assets
Current assets:
Cash and cash equivalents	$	10,872		$	2,361
Accounts receivable, net	438,331			553,066
Accounts receivable—affiliates	1,276			1,230
Inventories	598,818			586,831
Brokerage margin deposits	38,362			15,501
Fair value of forward fixed price contracts	10,384			1,942
Prepaid expenses and other current assets	60,409			36,714
Total current assets	1,158,452			1,197,645

Property and equipment, net	410,043			422,684
Intangible assets, net	37,927			40,065
Other assets	11,438			11,922
Total assets	$	1,617,860		$	1,672,316

Liabilities and partners’ equity
Current liabilities:
Accounts payable	$	362,700		$	443,469
Working capital revolving credit facility—current portion	211,833			193,198
Environmental liabilities—current portion	2,948			5,535
Trustee taxes payable	65,784			69,828
Accrued expenses and other current liabilities	41,510			30,494
Obligations on forward fixed price contracts and other derivatives	3,373			9,157
Total current liabilities	688,148			751,681

Working capital revolving credit facility—less current portion	340,167			293,502
Revolving credit facility	220,000			300,000
Environmental liabilities—less current portion	27,837			28,970
Other long-term liabilities	24,558			21,347
Total liabilities	1,300,710			1,395,500

Partners’ equity
Common unitholders (21,580,563 units issued and 21,549,723 units outstanding at September 30, 2011 and 13,293,139 units issued and 13,232,629 outstanding at December 31, 2010)	337,274			292,267
Subordinated unitholders (0 units issued and outstanding and 5,642,424 units issued and outstanding at September 30, 2011 and December 31, 2010, respectively)	—			(1,623		)
General partner interest (1.06% and 1.20% interest with 230,303 equivalent units outstanding at September 30, 2011 and December 31, 2010, respectively)	(554		)	(66		)
Accumulated other comprehensive loss	(19,570		)	(13,762		)
Total partners’ equity	317,150			276,816
Total liabilities and partners’ equity	$	1,617,860		$	1,672,316

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

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GLOBAL PARTNERS LP

CONSOLIDATED STATEMENTS OF INCOME

(In thousands, except per unit data)

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010

Sales	$	3,765,765		$	1,546,839		$	10,728,985		$	5,046,285
Cost of sales	3,716,486			1,511,744			10,578,885			4,931,461
Gross profit	49,279			35,095			150,100			114,824

Costs and operating expenses:
Selling, general and administrative expenses	17,166			17,246			57,085			47,715
Operating expenses	19,373			10,405			54,932			28,867
Restructuring charges	1,719			—			1,719			—
Amortization expenses	1,216			1,005			3,583			2,430
Total costs and operating expenses	39,474			28,656			117,319			79,012

Operating income	9,805			6,439			32,781			35,812

Interest expense	(7,947		)	(5,888		)	(23,478		)	(14,326		)

Income before income tax expense	1,858			551			9,303			21,486

Income tax expense	—			—			—			(387		)

Net income	1,858			551			9,303			21,099

Less: General partner’s interest in net income, including incentive distribution rights	(142		)	(72		)	(455		)	(518		)

Limited partners’ interest in net income	$	1,716		$	479		$	8,848		$	20,581

Basic net income per limited partner unit	$	0.08		$	0.03		$	0.42		$	1.30

Diluted net income per limited partner unit	$	0.08		$	0.03		$	0.41		$	1.28

Basic weighted average limited partner units outstanding	21,567			16,934			21,188			15,824

Diluted weighted average limited partner units outstanding	21,752			17,180			21,388			16,075

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)

	Nine Months Ended September 30,
	2011			2010
Cash flows from operating activities
Net income	$	9,303		$	21,099
Adjustments to reconcile net income to net cash used in operating activities:
Depreciation and amortization	22,725			12,733
Amortization of deferred financing fees	3,450			1,928
Bad debt expense	1,770			370
Stock-based compensation expense	333			76
Changes in operating assets and liabilities:
Accounts receivable	112,965			31,535
Accounts receivable – affiliate	(46		)	252
Inventories	(11,987		)	(65,859		)
Broker margin deposits	(22,861		)	7,566
Prepaid expenses, all other current assets and other assets	(28,107		)	(30,738		)
Accounts payable	(80,769		)	(34		)
Income taxes payable	—			(1,356		)
Trustee taxes payable	(4,044		)	(3,251		)
Change in fair value of forward fixed price contracts	(14,226		)	(9,880		)
Accrued expenses, all other current liabilities and other long-term liabilities	4,715			2,601
Net cash used in operating activities	(6,779		)	(32,958		)

Cash flows from investing activities
Acquisitions	—			(248,359		)
Capital expenditures	(7,471		)	(7,544		)
Proceeds from sale of property and equipment	955			47
Net cash used in investing activities	(6,516		)	(255,856		)

Cash flows from financing activities
Proceeds from public offering, net	69,626			84,584
Payments on (borrowings from) credit facilities, net	(14,700		)	231,900
Repurchase of common units	(658		)	—
Repurchased units withheld for tax obligations	(675		)	(404		)
Distributions to partners	(31,787		)	(23,336		)
Net cash provided by financing activities	21,806			292,744

Increase in cash and cash equivalents	8,511			3,930
Cash and cash equivalents at beginning of period	2,361			662
Cash and cash equivalents at end of period	$	10,872		$	4,592

Supplemental information
Cash paid during the period for interest	$	23,905		$	14,017
Non-cash conversion of subordinated unitholders	$	1,623		$	—

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, 2010	$	292,267		$	(1,623	)	$	(66	)	$	(13,762	)	$	276,816
Conversion of subordinated units to common units	(1,623		)	1,623			—			—			—
Proceeds from public offering, net	69,626			—			—			—			69,626
Stock-based compensation	333			—			—			—			333
Distributions to partners	(30,844		)	—			(943		)	—			(31,787		)
Repurchase of common units	(658		)	—			—			—			(658		)
Repurchased units withheld for tax obligations	(675		)	—			—			—			(675		)
Comprehensive income:
Net income	8,848			—			455			—			9,303
Other comprehensive income:
Change in fair value of cash flow hedges	—			—			—			(5,013		)	(5,013		)
Change in pension liability	—			—			—			(795		)	(795		)
Total comprehensive income	—			—			—			—			3,495
Balance at September 30, 2011	$	337,274		$	—		$	(554	)	$	(19,570	)	$	317,150

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, renewable fuels and small amounts of natural gas and also provides ancillary services to companies. The Partnership also receives revenue from retail sales of gasoline, convenience store sales and gas station rental income.

The Partnership has five operating subsidiaries: Global Companies LLC, its subsidiary, Glen Hes Corp., Global Montello Group Corp. (“GMG”), 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. GMG conducts the Partnership’s end user business, including certain aspects of its retail gasoline business. Global Energy was formed to conduct the Partnership’s natural gas operations. 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 1.06% 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. Affiliates of the General Partner, including its directors and executive officers, own 5,442,590 common units, representing a 25% limited partner interest.

Basis of Presentation

The accompanying consolidated financial statements as of September 30, 2011 and December 31, 2010 and for the three and nine months ended September 30, 2011 and 2010 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, 2010 and notes thereto contained in the Partnership’s Annual Report on Form 10-K. The significant accounting policies described in Note 2, “Summary of Significant Accounting Policies,” of such Annual Report on Form 10-K are the same used in preparing the accompanying consolidated financial statements.

The results of operations for the three and nine months ended September 30, 2011 are not necessarily indicative of the results of operations that will be realized for the entire year ending December 31, 2011. The consolidated balance sheet at December 31, 2010 has been derived from the audited consolidated financial statements included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2010.

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1. Organization and Basis of Presentation (continued)

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.

Concentration of Risk

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

	Three Months Ended September 30,		Nine Months Ended September 30,
	2011	2010	2011	2010
Gasoline sales: gasoline and blendstocks such as ethanol and naphtha	75%	69%	68%	58%
Distillate sales: home heating oil, diesel and kerosene	21%	26%	28%	37%
Residual oil sales	4%	5%	4%	5%
	100%	100%	100%	100%

The Partnership had one significant customer, ExxonMobil Oil Corporation (“ExxonMobil”), who accounted for approximately 18% and 22% of total sales for the three months ended September 30, 2011 and 2010, respectively, and approximately 20% of total sales for each of the nine month periods ended September 30, 2011 and 2010.

Note 2. Net Income Per Limited Partner Unit

Under the Partnership’s partnership agreement, for any quarterly period, the incentive distribution rights (“IDRs”) participate in net income only to the extent of the amount of cash distributions actually declared, thereby excluding the IDRs from participating in the Partnership’s undistributed net income or losses. Accordingly, the Partnership’s undistributed net income is assumed to be allocated to the common and subordinated unit holders, or limited partners’ interest, and to the General Partner’s general partner interest. On February 16, 2011, all subordinated units converted to common units.

On April 20, 2011, the board of directors of the General Partner declared a quarterly cash distribution of $0.50 per unit for the period from January 1, 2011 through March 31, 2011. On July 21, 2011, the board of directors of the General Partner declared a quarterly cash distribution of $0.50 per unit for the period from April 1, 2011 through June 30, 2011. On October 19, 2011, the board of directors of the General Partner declared a quarterly cash distribution of $0.50 per unit for the period from July 1, 2011 through September 30, 2011. These declared cash distributions resulted in incentive distributions to the General Partner, as the holder of the IDRs, and enabled the Partnership to exceed its first target level distribution with respect to such IDRs. See Note 8, “Cash Distributions” for further information.

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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

The following table provides a reconciliation of net income and the assumed allocation of net income to the limited partners’ interest for purposes of computing net income per limited partner unit for the three and nine months ended September 30, 2011 and 2010 (in thousands, except per unit data):

	Three Months Ended September 30, 2011
				Limited			General
				Partner			Partner
Numerator:	Total			Interest			Interest			IDRs
Net income (1)	$	1,858		$	1,716		$	142		$	—

Declared distribution	$	11,028		$	10,790		$	116		$	122
Assumed allocation of undistributed net income	(9,170		)	(9,074		)	(96		)	—
Assumed allocation of net income	$	1,858		$	1,716		$	20		$	122

Denominator:
Basic weighted average limited partner units outstanding				21,567
Dilutive effect of phantom units				185
Diluted weighted average limited partner units outstanding				21,752

Basic net income per limited partner unit				$	0.08
Diluted net income per limited partner unit				$	0.08

	Three Months Ended September 30, 2010
				Limited			General
				Partner			Partner
Numerator:	Total			Interest			Interest			IDRs
Net income (2)	$	551		$	479		$	72		$	—

Declared distribution	$	8,603		$	8,405		$	114		$	84
Assumed allocation of undistributed net income	(8,052		)	(7,926		)	(126		)	—
Assumed allocation of net income	$	551		$	479		$	(12	)	$	84

Denominator:
Basic weighted average limited partner units outstanding				16,934
Dilutive effect of phantom units				246
Diluted weighted average limited partner units outstanding				17,180

Basic net income per limited partner unit				$	0.03
Diluted net income per limited partner unit				$	0.03

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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

	Nine Months Ended September 30, 2011
				Limited			General
				Partner			Partner
Numerator:	Total			Interest			Interest			IDRs
Net income (1)	$	9,303		$	8,848		$	455		$	—

Declared distribution	$	33,084		$	32,370		$	348		$	366
Assumed allocation of undistributed net income	(23,781		)	(23,522		)	(259		)	—
Assumed allocation of net income	$	9,303		$	8,848		$	89		$	366

Denominator:
Basic weighted average limited partner units outstanding				21,188
Dilutive effect of phantom units				200
Diluted weighted average limited partner units outstanding				21,388

Basic net income per limited partner unit				$	0.42
Diluted net income per limited partner unit				$	0.41

	Nine Months Ended September 30, 2010
				Limited			General
				Partner			Partner
Numerator:	Total			Interest			Interest			IDRs
Net income (2)	$	21,099		$	20,581		$	518		$	—

Declared distribution	$	25,513		$	24,961		$	338		$	214
Assumed allocation of undistributed net income	(4,414		)	(4,380		)	(34		)	—
Assumed allocation of net income	$	21,099		$	20,581		$	304		$	214

Denominator:
Basic weighted average limited partner units outstanding				15,824
Dilutive effect of phantom units				251
Diluted weighted average limited partner units outstanding				16,075

Basic net income per limited partner unit				$	1.30
Diluted net income per limited partner unit				$	1.28

_________________________

(1) Calculation includes the effect of the public offerings in November 2010 and February 2011 (see Note 14) and, as a result, the general partner interest was reduced to 1.06% for the three months ended September 30, 2011 and, based on a weighted average, 1.10% for the nine months ended September 30, 2011.

(2) Calculation includes the effect of the public offering in March 2010 (see Note 14) and, as a result, the general partner interest was reduced to 1.34% for the three months ended September 30, 2010 and, based on a weighted average, 1.60% for the nine months ended September 30, 2010.

Limited partner units outstanding exclude common units held by the General Partner 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).

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 3. Comprehensive (Loss) Income

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2011			2010			2011			2010
Net income	$	1,858		$	551		$	9,303		$	21,099
Change in fair value of cash flow hedges	(5,193		)	(3,774		)	(5,013		)	(10,885		)
Change in pension liability	(720		)	646			(795		)	88
Total comprehensive (loss) income	$	(4,055	)	$	(2,577	)	$	3,495		$	10,302

Note 4. Inventories

Except for its convenience store inventory, 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. In addition, the Partnership has convenience store inventory which is carried at the lower of historical cost or market.

Inventories consisted of the following (in thousands):

	September 30, 2011		December 31, 2010
Distillates: home heating oil, diesel and kerosene	$	362,636	$	377,123
Gasoline	133,876		115,542
Residual oil	25,898		35,749
Blend stock	73,765		55,919
Total	596,175		584,333
Convenience store inventory	2,643		2,498
Total	$	598,818	$	586,831

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 $42.0 million and $126.8 million at September 30, 2011 and December 31, 2010, respectively. Negative exchange balances are accounted for as accounts payable and amounted to $46.2 million and $115.2 million at September 30, 2011 and December 31, 2010, respectively. Exchange transactions are valued using current quoted market prices.

Note 5. Derivative Financial Instruments

Accounting and reporting guidance for derivative instruments and hedging activities requires that an entity recognize derivatives as either assets or liabilities on the balance sheet and measure the instruments at fair value. Changes in the fair value of the derivative are to be recognized currently in earnings, unless specific hedge accounting criteria are met.

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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 September 30, 2011:

	Units (1)			Unit of Measure
Product Contracts
Long	11,735			Thousands of barrels
Short	(15,472		)	Thousands of barrels

Natural Gas Contracts
Long	18,432			Thousands of decatherms
Short	(18,432		)	Thousands of decatherms

Interest Rate Collar	$	100		Millions of dollars

Swap	$	100		Millions of dollars

Interest Rate Cap	$	100		Millions 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 and renewable fuels 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 for the three and nine months ended September 30, 2011 and 2010.

The Partnership also uses futures contracts and swap agreements to hedge exposure under forward fixed price purchase and sale commitments. These agreements are intended to hedge the cost component of virtually all of the Partnership’s forward fixed price purchase and sale commitments. Changes in the fair value of these contracts and agreements, 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 commitments 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 for the three and nine months ended September 30, 2011 and 2010.

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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 September 30, 2011 and December 31, 2010 (in thousands):

		September 30,		December 31,
	Balance Sheet	2011		2010
Asset Derivatives	Location (Net)	Fair Value		Fair Value
Derivatives designated as hedging instruments and firm commitments
Product contracts (1)	(2)	$	7,561	$	3,896

Derivatives not designated as hedging instruments
Product and natural gas contracts	(2)	4,988		3,049

Total asset derivatives		$	12,549	$	6,945

Liability Derivatives
Derivatives designated as hedging instruments and firm commitments
Product contracts (1)	(3)	$	222	$	13,538

Derivatives not designated as hedging instruments
Product and natural gas contracts	(3)	4,863		2,896

Total liability derivatives		$	5,085	$	16,434

(1) Includes forward fixed price purchase and sale contracts as recognized in the Partnership’s consolidated balance sheets at September 30, 2011 and December 31, 2010.

(2) Fair value of forward fixed price contracts and prepaid expenses and other current assets.

(3) Obligations on forward fixed price contracts and other derivatives 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 nine months ended September 30, 2011 and 2010 (in thousands):

Amount of Gain (Loss) Recognized in

Income on Derivatives

Location of Gain (Loss)

Three Months Ended

Nine Months Ended

Derivatives in Fair Value

Recognized in

September 30,

Hedging Relationships

Income on Derivative

2011

2010

2011

2010

Product contracts

Cost of sales

30,711

(34,725

)

(62,732

)

7,478

Amount of Gain (Loss) Recognized in

Income on Hedged Items

Location of Gain (Loss)

Three Months Ended

Nine Months Ended

Hedged Items in Fair Value

Recognized in

September 30,

Hedged Relationships

Income on Hedged Items

2011

2010

2011

2010

Inventories and forward fixed price contracts

Cost of sales

(30,681

)

34,811

63,030

(7,494

)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 5. Derivative Financial Instruments (continued)

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

The 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):

	September 30, 2011			December 31, 2010
Futures contracts	$	7,108		$	(6,480	)
Swaps and other, net	(97		)	(735		)
Total	$	7,011		$	(7,215	)

The total balances of $7.0 million and ($7.2) million reflect the fair value of the forward fixed price contract asset/(liability) net of the corresponding asset/(liability) in the accompanying consolidated balance sheets at September 30, 2011 and December 31, 2010, respectively.

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 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 has a daily margin requirement with its brokers based on the prior day’s market results on open futures contracts. The brokerage margin balance was $38.4 million and $15.5 million at September 30, 2011 and December 31, 2010, 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 two clearing brokers, both major financial institutions, for all New York Mercantile Exchange (“NYMEX”) and Chicago Mercantile Exchange (“CME”) derivative transactions and the right of offset exists. Accordingly, the fair value of derivative instruments is presented on a net basis in the consolidated balance sheets. Exposure on forward purchase and sale commitments and swap and certain option agreements is limited to the amount of the recorded fair value as of the balance sheet dates.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 5. Derivative Financial Instruments (continued)

The Partnership generally enters into master netting arrangements to mitigate counterparty credit risk with respect to its derivatives. Master netting arrangements are standardized contracts that govern all specified transactions with the same counterparty and allow the Partnership to terminate all contracts upon occurrence of certain events, such as a counterparty’s default or bankruptcy. Because these arrangements provide the right of offset, and the Partnership’s intent and practice is to offset amounts in the case of contract terminations, the Partnership records fair value of derivative positions on a net basis.

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 are reported as a component of other comprehensive income and reclassified into interest expense 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 and accounted for as a cash flow hedge. The first collar, which became effective on May 14, 2007 and expired on May 14, 2011, was 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 on the revolving credit facility.

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 on the working capital revolving credit facility (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 September 30, 2011, the one-month LIBOR rate of 0.22% was lower than the floor rate. As a result, the Partnership will remit to the respective financial institution the difference between the floor rate and the current rate which amounted to approximately $200,000 and, at September 30, 2011, such amount was recorded in accrued expenses and other current liabilities in the accompanying consolidated balance sheet. The fair values of the second collar, excluding accrued interest, were liabilities of approximately $4.5 million and $4.8 million as of September 30, 2011 and December 31, 2010, respectively, and were recorded in both other long-term liabilities and accumulated other comprehensive income in the accompanying consolidated balance sheets. Hedge effectiveness was assessed at inception and is assessed quarterly, prospectively and retrospectively, using 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 collar’s strike rates.

In October 2009, the Partnership executed a forward starting swap with a major financial institution. The swap, which became effective on May 16, 2011 and expires on May 16, 2016, is used to hedge the variability in interest payments due to changes in the one-month LIBOR swap curve with respect to $100.0 million of one-month LIBOR-based borrowings on the revolving credit facility at a fixed rate of 3.93%. The fair values of the swap were liabilities of approximately $12.6 million and $7.3 million as of September 30, 2011 and December 31, 2010, respectively, and were recorded in other long-term liabilities in the accompanying consolidated balance sheets. Hedge effectiveness was assessed at inception and will be assessed quarterly, prospectively and retrospectively, using regression analysis. The changes in the fair value of the swap are expected to be highly effective in offsetting the changes in interest rate payments attributable to fluctuations in the one-month LIBOR swap curve.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 5. Derivative Financial Instruments (continued)

On April 8, 2011, the Partnership executed an interest rate cap with a major financial institution. The rate cap, which became effective on April 13, 2011 and expires on April 13, 2016, is used to hedge the variability in interest payments due to changes in the one-month LIBOR rate above 5.5% with respect to $100.0 million of one-month LIBOR-based borrowings on the working capital revolving credit facility. The fair value of the rate cap was an asset of approximately $175,000 as of September 30, 2011 and was recorded in both other assets and accumulated other comprehensive income in the accompanying balance sheet. Hedge effectiveness was assessed at inception and will be assessed quarterly, prospectively and retrospectively, by (i) comparing the critical terms of the rate cap and the hedged forecasted transactions, (ii) evaluating the counterparty’s ability to honor its obligations under the rate cap agreement; and (iii) ensuring the interest payment cash flows remain probable of occurring. The changes in the fair value of the rate cap are expected to be highly effective in offsetting the changes in interest rate payments attributable to fluctuations in the one-month LIBOR rate above the rate cap’s strike rate.

The following table presents the fair value of the Partnership’s derivative instruments involved in cash flow hedging relationships and their location in the Partnership’s consolidated balance sheets at September 30, 2011 and December 31, 2010 (in thousands):

		September 30,		December 31,
Derivatives Designated as	Balance Sheet	2011		2010
Hedging Instruments	Location	Fair Value		Fair Value

Asset derivatives
Interest rate cap	Other assets	$	175	$	—

Liability derivatives
Interest rate collars	Other long-term liabilities	$	4,469	$	6,042
Swap	Other long-term liabilities	12,638		7,296
Total liability derivatives		$	17,107	$	13,338

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 and partners’ equity for the three and nine months ended September 30, 2011 and 2010 (in thousands):

							Recognized in Income										Recognized in Income
							on Derivatives										on Derivatives
	Amount of Gain (Loss)						(Ineffectiveness Portion				Amount of Gain (Loss)						(Ineffectiveness Portion
	Recognized in Other						and Amount Excluded				Recognized in Other						and Amount Excluded
	Comprehensive Income						from Effectiveness				Comprehensive Income						from Effectiveness
	on Derivatives						Testing)				on Derivatives						Testing)
Derivatives in	Three Months Ended						Three Months Ended				Nine Months Ended						Nine Months Ended
Cash Flow	September 30,						September 30,				September 30,						September 30,
Hedging Relationship	2011			2010			2011		2010		2011			2010			2011		2010

Interest rate collars	$	66		$	(343	)	$	—	$	—	$	1,573		$	(872	)	$	—	$	—
Swap	(3,075		)	(3,431		)	—		—		(5,343		)	(10,013		)	—		—
Interest rate cap	(2,184		)	—			—		—		(1,243		)	—			—		—
Total	$	(5,193	)	$	(3,744	)	$	—	$	—	$	(5,013	)	$	(10,885	)	$	—	$	—

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 5. Derivative Financial Instruments (continued)

Ineffectiveness related to the interest rate collars and the swap is recognized as interest expense and was immaterial for the three and nine months ended September 30, 2011 and 2010. The effective portion related to the interest rate collars that was originally reported in other comprehensive income and reclassified to earnings was $0.6 million and $1.5 million for the three months ended September 30, 2011 and 2010, respectively, and $3.1 million and $4.5 million for the nine months ended September 30, 2011 and 2010, respectively. None of the effective portion related to the interest rate cap that was originally reported in other comprehensive income was reclassified into earnings for the three and nine months ended September 30, 2011.

Derivatives Not Involved in a Hedging 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 inherent in the business, such as 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 and renewable fuels products at any one point in time.

The following table presents the amount of gains and losses from derivatives not involved in a hedging relationship recognized in the Partnership’s consolidated statements of income for the three and nine months ended September 30, 2011 and 2010 (in thousands):

		Amount of Gain (Loss)		Amount of Gain (Loss)
	Location of	Recognized in Income		Recognized in Income
	Gain (Loss)	on Derivatives		on Derivatives
	Recognized in	Three Months Ended		Nine Months Ended
Derivatives Not Designated as	Income on	September 30,		September 30,
Hedging Instruments	Derivatives	2011	2010	2011	2010

Product contracts	Cost of sales	$ 6,789	$ 1,828	$ 9,116	$ 2,959

Note 6. Debt

On January 26, 2011, the Partnership requested an increase in the working capital revolving credit facility in an amount equal to $100.0 million, and on February 11, 2011, certain lenders under the Partnership’s Amended and Restated Credit Agreement dated May 14, 2010, as amended (the “Credit Agreement”) committed to the $100.0 million increase which increased the total available commitments under the Credit Agreement to $1.25 billion. The Credit Agreement will mature on May 14, 2014.

There are two facilities under the Credit Agreement:

· a working capital revolving credit facility to be used for working capital purposes and letters of credit in the principal amount equal to the lesser of the Partnership’s borrowing base and $900.0 million; and

· a $350.0 million revolving credit facility to be used for acquisitions and general corporate purposes.

In addition, the Credit Agreement has an accordion feature whereby the Partnership may request on the same terms and conditions of its then existing Credit Agreement, provided no Event of Default (as defined in the Credit Agreement) then exists, an increase to the revolving credit facility, the working capital revolving credit facility, or both, by up to another $100.0 million, for a total credit facility of up to $1.35 billion. Any such request for an increase by the Partnership must be in a minimum amount of $5.0 million, and the revolving credit facility may not be increased by more than $50.0 million. The Partnership cannot provide assurance, however, that its lending group will agree to fund any request by the Partnership for additional amounts in excess of the total available commitments of $1.25 billion.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 6. Debt (continued)

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

During the period from January 1, 2010 through May 13, 2010, borrowings under the working capital revolving credit facility bore 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 previous credit agreement, which in turn depended upon the Combined Interest Coverage Ratio (as defined in the previous credit agreement). Borrowings under the revolving credit facility bore 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 previous credit agreement, which in turn depended upon the Combined Interest Coverage Ratio under the previous credit agreement.

Commencing May 14, 2010, borrowings under the working capital revolving credit facility bear interest at (1) the Eurodollar rate plus 2.50% to 3.00%, (2) the cost of funds rate plus 2.50% to 3.00%, or (3) the base rate plus 1.50% to 2.00%, each depending on the pricing level provided in the Credit Agreement, which in turn depends upon the Utilization Amount (as defined in the Credit Agreement).

During the period from May 14, 2010 through September 7, 2010, borrowings under the revolving credit facility bore interest at (1) the Eurodollar rate plus 3.00% to 3.25%, (2) the cost of funds rate plus 3.00% to 3.25%, or (3) the base rate plus 2.00% to 2.25%, each depending on the pricing level provided in the Credit Agreement, which in turn depended upon the Combined Senior Secured Leverage Ratio (as defined in the Credit Agreement). Commencing September 8, 2010, borrowings under the revolving credit facility bear interest at (1) the Eurodollar rate plus 3.00% to 3.875%, (2) the cost of funds rate plus 3.00% to 3.875%, or (3) the base rate plus 2.00% to 2.875%, each depending on the pricing level provided in the Credit Agreement, which in turn depends upon the Combined Total Leverage Ratio (as defined in the Credit Agreement).

The average interest rates for the Credit Agreement were 4.0% and 4.1% for the three months ended September 30, 2011 and 2010, respectively, and 4.0% and 3.8% for the nine months ended September 30, 2011 and 2010, respectively.

The Partnership currently has a zero premium interest rate collar, a swap and an interest rate cap, all of which are used to hedge the variability in interest payments under the Credit Agreement due to changes in LIBOR rates. See Note 5 for additional information on these cash flow hedges.

The Partnership incurs a letter of credit fee of 2.50% – 3.00% per annum for each letter of credit issued. In addition, the Partnership incurs a commitment fee on the unused portion of each facility under the Credit Agreement equal to 0.50% per annum.

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 6. Debt (continued)

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 $340.2 million and $293.5 million at September 30, 2011 and December 31, 2010, 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 $211.8 million and $193.2 million at September 30, 2011 and December 31, 2010, respectively, representing the amounts the Partnership expects to pay down during the course of the year.

As of September 30, 2011, the Partnership had total borrowings outstanding under the Credit Agreement of $772.0 million, including $220.0 million outstanding on the revolving credit facility. In addition, the Partnership had outstanding letters of credit of $167.3 million. Subject to borrowing base limitations, the total remaining availability for borrowings and letters of credit at September 30, 2011 and December 31, 2010 was $310.7 million and $252.6 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 as a result thereof, and limitations on the Partnership’s ability to grant liens, make certain loans or investments, incur additional indebtedness or guarantee other indebtedness, make any material change to the nature of the Partnership’s business or undergo a fundamental change, make any material dispositions, acquire another company, enter into a merger, consolidation, sale leaseback transaction or purchase of assets, or make capital expenditures in excess of specified levels.

The Credit Agreement imposes financial covenants that require the Partnership to maintain certain minimum working capital amounts, capital expenditure limits, a minimum EBITDA, a minimum combined interest coverage ratio, a maximum senior secured leverage ratio and a maximum total leverage ratio. On July 19, 2011, the Partnership entered into a Second Amendment to the Credit Agreement which amended the Credit Agreement and modified certain financial covenants. The Partnership was in compliance with the foregoing covenants at September 30, 2011. The Credit Agreement also contains a representation whereby there can be no event or circumstance, either individually or in the aggregate, that has had or could reasonably be expected to have a Material Adverse Effect (as defined in the Credit Agreement). In addition, the Credit Agreement limits distributions by the Partnership to its unitholders to the amount of the Partnership’s Available Cash (as defined in its partnership agreement).

The lending group under the Credit Agreement is comprised of the following institutions: Bank of America, N.A.; JPMorgan Chase Bank, N.A.; Wells Fargo Bank, N.A.; Societe Generale; Standard Chartered Bank; RBS Citizens, National Association; BNP Paribas; Cooperative Centrale Raiffeisen-Boerenleen bank B.A., “Rabobank Nederland” New York Branch; Sovereign Bank; Credit Agricole Corporate and Investment Bank; Keybank National Association; Toronto Dominion (New York); RB International Finance (USA) LLC (formerly known as RZB Finance LLC); Royal Bank of Canada; Raymond James Bank, FSB; Barclays Bank plc; Webster Bank National Association; Natixis, New York Branch; DZ Bank AG Deutsche Zentral-Genossenschaftsbank Frankfurt Am Main; Branch Banking & Trust Company; and Sumitomo Mitsui Banking Corporation.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 7. Related Party Transactions

The Partnership is a party to a Second Amended and Restated Terminal Storage Rental and Throughput Agreement, as amended, with Global Petroleum Corp. (“GPC”), an affiliate of the Partnership that is 100% owned by members of the Slifka family. The agreement, which extends through July 31, 2014 with annual renewal options thereafter, is accounted for as an operating lease. The expenses under this agreement totaled approximately $2.2 million for each of the three months ended September 30, 2011 and 2010 and approximately $6.5 million for each of the nine months ended September 30, 2011 and 2010.

Pursuant to an Amended and Restated Services Agreement with GPC, GPC provides certain terminal operating management services to the Partnership and uses certain administrative, accounting and information processing services of the Partnership. The expenses from these services totaled approximately $24,000 and $21,900 for the three months ended September 30, 2011 and 2010, respectively, and approximately $72,000 and $65,600 for the nine months ended September 30, 2011 and 2010, respectively. These charges were recorded in selling, general and administrative expenses in the accompanying consolidated statements of income. The agreement is for an indefinite term, and either party may terminate its receipt of some or all of the services thereunder upon 180 days’ notice at any time. As of September 30, 2011, no such notice of termination was given by either party.

Pursuant to the Partnership’s Amended and Restated Services Agreement with Alliance Energy LLC (“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 $47,000 and $49,000 for the three months ended September 30, 2011 and 2010, respectively, and $140,000 and $147,000 for the nine months ended September 30, 2011 and 2010, respectively. These fees were recorded as an offset to selling, general and administrative expenses in the accompanying consolidated statements of income. The agreement is for an indefinite term, and Alliance may terminate its receipt of some or all of the services thereunder upon 180 days’ notice at any time. As of September 30, 2011, no such notice of termination was given by Alliance.

The Partnership sells refined petroleum products and renewable fuels to Alliance at prevailing market prices at the time of delivery. Sales to Alliance were approximately $66.3 million and $4.1 million for the three months ended September 30, 2011 and 2010, respectively, and $126.2 million and $17.6 million for the nine months ended September 30, 2011 and 2010, respectively. Sales for the three and nine months ended September 30, 2011 include sales of Mobil-branded fuel to Alliance pursuant to the Mobil franchise agreement entered into by Global Companies LLC and Alliance, effective March 1, 2011.

In addition, Global Companies LLC and GMG, wholly owned subsidiaries of the Partnership, entered into management agreements with Alliance in connection with the Partnership’s September 2010 acquisition of retail gas stations from ExxonMobil (see Note 10). The management fee and overhead reimbursement were approximately $0.7 million and $0.4 million, respectively, for the three months ended September 30, 2011 and $2.0 million and $1.2 million, respectively, for the nine months ended September 30, 2011.

The General Partner employs substantially all of the Partnership’s employees. The Partnership reimburses the General Partner for expenses incurred in connection with these employees. The expenses for the three months ended September 30, 2011 and 2010, including payroll, payroll taxes and bonus accruals, were $11.0 million and $8.8 million, respectively, and $34.8 million and $28.6 million for the nine months ended September 30, 2011 and 2010, respectively. The Partnership also reimburses the General Partner for its contributions under the General Partner’s 401(k) Savings and Profit Sharing Plan and the General Partner’s qualified and non-qualified pension plans.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 7. Related Party Transactions (continued)

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):

	September 30,		December 31,
	2011		2010
Receivables from Alliance	$	216	$	296
Receivables from GPC	284		224
Receivables from the General Partner (1)	776		710
Total	$	1,276	$	1,230

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

Note 8. Cash Distributions

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

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

The Partnership will make distributions of Available Cash from distributable cash flow for any quarter in the following manner: 98.94% to the common unitholders, pro rata, and 1.06% to the General Partner, until the Partnership distributes for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter; and thereafter, cash in excess of the minimum quarterly distribution is distributed to the unitholders and the General Partner based on the percentages as provided below.

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

	Total Quarterly Distribution	Marginal Percentage Interest in Distributions
	Target Amount	Unitholders	General Partner
Minimum Quarterly Distribution	$0.4625	98.94%	1.06%
First Target Distribution	$0.4625	98.94%	1.06%
Second Target Distribution	above $0.4625 up to $0.5375	85.94%	14.06%
Third Target Distribution	above $0.5375 up to $0.6625	75.94%	24.06%
Thereafter	above $0.6625	50.94%	49.06%

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 8. Cash Distributions (continued)

The Partnership paid the following cash distribution during 2011 (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

02/14/11 (1)(2)	$ 0.50	$ 6,647	$2,821	$115	$ 108	$ 9,691
05/13/11 (2)	$ 0.50	$10,790	—	$116	$ 122	$ 11,028
8/12/11 (2)	$ 0.50	$10,790	—	$116	$ 122	$ 11,028

(1) On February 16, 2011, based upon meeting certain distribution and performance tests provided in the Partnership’s partnership agreement, all 5,642,424 subordinated units converted to common units. Prior to the conversion and the February 2011 offering, the Partnership made this distribution in the following manner: firstly, 98.80% to the common unitholders, pro rata, and 1.20% to the General Partner, until the Partnership distributed for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter; secondly, 98.80% to the common unitholders, pro rata, and 1.20% to the General Partner, until the Partnership distributed 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, 98.80% to the subordinated unitholders, pro rata, and 1.20% to the General Partner, until the Partnership distributed for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter.

(2) This distribution of $0.50 per unit resulted in the Partnership exceeding its first target level distribution for the fourth quarter of 2010 and first and second quarters of 2011. As a result, the General Partner, as the holder of the IDRs, received an incentive distribution.

In addition, on October 19, 2011, the board of directors of the General Partner declared a quarterly cash distribution of $0.50 per unit ($2.00 per unit on an annualized basis) for the period from July 1, 2011 through September 30, 2011. On November 14, 2011, the Partnership will pay this cash distribution to its common unitholders of record as of the close of business November 3, 2011. This distribution will result in the Partnership exceeding its first target level distribution for the quarter ended September 30, 2011.

Note 9. Segment Reporting

The Partnership’s operating segments are based upon the revenue sources for which discrete financial information is reviewed by the chief operating decision maker (the “CODM”) and include Wholesale, Commercial, Retail Gasoline, Convenience Stores and Rental Income from gas stations. Each of these operating segments generates revenues and incurs expenses and is evaluated for operating performance on a regular basis. These operating segments are aggregated into two reportable segments as discussed below.

The Partnership primarily engages in the wholesale and commercial distribution of refined petroleum products and renewable fuels and small amounts of natural gas. The Partnership’s primary business is organized within two reporting segments, Wholesale and Commercial, based on the way the CODM 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, 2010.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 9. Segment Reporting (continued)

In the Wholesale reporting segment, which represents a standalone reporting segment, the Partnership sells gasoline (including blendstocks such as ethanol and naphtha) and diesel to unbranded and Mobil-branded retail gasoline stations and other resellers of transportation fuels and home heating oil, diesel, kerosene and residual oil to 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 or exchange arrangements.

Within the Commercial reporting segment, the Partnership aggregates the Commercial and Retail Gasoline operating segments into this reporting segment based upon similar products, classes of customer, distribution methods and economic characteristics. The Commercial segment includes (1) sales and deliveries of unbranded gasoline, home heating oil, diesel, kerosene, residual oil, renewable fuels and small amounts of natural gas to end user customers in the public sector and to large commercial and industrial end users (in the case of commercial and industrial end user customers, the Partnership sells products primarily either through a competitive bidding process or through contracts of various terms), (2) sales of custom blended distillates and residual oil delivered by barges or from a terminal dock through bunkering activity, and (3) sales of Mobil-branded gasoline to end users. Commercial segment end user customers include Mobil-branded gasoline customers at the Partnership’s directly operated gas stations, federal and state agencies, municipalities, large industrial companies, many autonomous authorities such as transportation authorities and water resource authorities, colleges and universities and a group of small utilities. 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 Convenience Stores and Rental Income operating segments individually are not material and, therefore, do not meet the quantitative and qualitative metrics for disclosure as a reportable segment on a standalone basis. Further, these segments do not have similar characteristics with the other operating segments that would enable these segments to be aggregated together with another operating segment. As such, the Convenience Stores and Rental Income segments are not reportable segments and are, therefore, aggregated into an “all other” category for disclosure purposes.

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

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Note 9. Segment Reporting (continued)

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Wholesale Segment:	2011			2010			2011			2010
Sales
Gasoline (1)	$	2,746,585		$	1,066,764		$	6,982,846		$	2,929,257
Distillates	712,939			376,878			2,889,373			1,778,730
Residual oil	1,195			8,505			24,880			28,902
Total	$	3,460,719		$	1,452,147		$	9,897,099		$	4,736,889
Net product margin (2)
Gasoline	$	26,779		$	16,412		$	76,123		$	48,333
Distillates	10,153			18,440			36,336			58,920
Residual oil	1,245			1,864			4,756			7,154
Total	$	38,177		$	36,716		$	117,215		$	114,407
Commercial Segment:
Sales (1)	$	289,299		$	94,692		$	787,117		$	309,396
Net product margin (2)	$	9,268		$	2,318		$	27,642		$	10,040
All Other:
Sales (1)	$	15,747		$	—		$	44,769		$	—
Net product margin (2)	$	7,938		$	—		$	23,506		$	—
Combined sales and net product margin:
Sales	$	3,765,765		$	1,546,839		$	10,728,985		$	5,046,285
Net product margin (2)	$	55,383		$	39,034		$	168,363		$	124,447
Depreciation allocated to cost of sales	(6,104		)	(3,939		)	(18,263		)	(9,623		)
Combined gross profit	$	49,279		$	35,095		$	150,100		$	114,824

__________________________

(1) On September 30, 2010, the Partnership completed its acquisition of retail gas stations and supply rights from ExxonMobil (see Note 10). As these assets were not in place for a substantial portion of the quarter ended September 30, 2010, the above results are not directly comparable for periods prior to September 2010.

(2) 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 9. Segment Reporting (continued)

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2011			2010			2011			2010
Combined gross profit	$	49,279		$	35,095		$	150,100		$	114,824
Operating costs and expenses not allocated to operating segments:
Selling, general and administrative expenses	17,166			17,246			57,085			47,715
Operating expenses	19,373			10,405			54,932			28,867
Restructuring charges	1,719			—			1,719			—
Amortization expenses	1,216			1,005			3,583			2,430
Total operating costs and expenses	39,474			28,656			117,319			79,012
Operating income	9,805			6,439			32,781			35,812
Interest expense	(7,947		)	(5,888		)	(23,478		)	(14,326		)
Income tax expense	—			—			—			(387		)
Net income	$	1,858		$	551		$	9,303		$	21,099

There were no foreign sales for the three and nine months ended September 30, 2011 and 2010. The Partnership has no foreign assets.

Segment Assets

In connection with its acquisition of retail gas stations from ExxonMobil (see Note 10), the Partnership acquired assets of approximately $232.3 million, of which approximately $152.2 million of property and equipment was allocated to the Wholesale segment as of the acquisition date. There have been no material additions, dispositions or retirement of these assets as of September 30, 2011. Due to the commingled nature and uses of the remainder of the Partnership’s assets, it is not reasonably possible for the Partnership to allocate these assets between its reportable segments.

Note 10. Acquisition

Retail Gas Stations/Fuel Supply Acquisition — On September 30, 2010, the Partnership completed its acquisition of retail gas stations and supply rights from ExxonMobil for cash consideration of approximately $202.3 million, plus the assumption of certain environmental liabilities (see Note 11). In addition, the Partnership purchased approximately $4.2 million of convenience store inventory and gasoline and diesel inventory in the ordinary course of business that was stored at the acquired sites. Additionally, the Partnership acquired the right to supply Mobil-branded fuel to such stations and to Mobil-branded stations that are owned and operated by independent dealers in these states. The Partnership outsources the day-to-day management and operations of these locations to Alliance.

The Partnership financed the acquisition through borrowings under its Credit Agreement. This acquisition was accounted for as a business combination.

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Note 10. Acquisition (continued)

The following table presents the allocation of the cash consideration to the estimated fair value of the assets acquired and environmental liabilities assumed (in thousands):

Assets purchased:
Buildings and improvements	$	59,271
Land	118,634
Fixtures and equipment	47,008
Intangibles	7,400
Total assets purchased	232,313
Less environmental liabilities assumed	(30,000		)
Total cash consideration	$	202,313

The intangible assets acquired in the transaction consist of the following (in thousands):

Description	Gross Carrying Amount		Accumulated Amortization			Net Intangible Assets		Amortization Period
Supply contracts	$	7,400	$	(1,603	)	$	5,797	5 years

Amortization expense was approximately $0.4 million and $1.1 million for the three and nine months ended September 30, 2011.

Valuation of Intangible Assets — The purchase price for the above acquisition was allocated to assets acquired and liabilities assumed based on their estimated fair values. The Partnership then allocated the purchase price in excess of net tangible assets acquired to identifiable intangible assets, based upon a detailed valuation that used information and assumptions provided by management.

As part of the purchase price allocation, identifiable intangible assets include supply contracts. The Partnership used the income approach to value the intangibles. This approach calculates fair value by estimating future cash flows attributable to each intangible asset and discounting them to present value at a risk-adjusted discount rate.

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

The estimated remaining amortization expense for intangible assets acquired in connection with the 2010 acquisition of retail gas stations from ExxonMobil for each of the five succeeding years and thereafter is as follows (in thousands):

2011 (10/1/11 – 12/31/11)	$	370
2012	1,480
2013	1,480
2014	1,480
2015	987
Thereafter	—
Total	$	5,797

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Note 11. Environmental Liabilities

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

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

In connection with the September 2010 acquisition of the retail gas stations from ExxonMobil (see Note 10), the Partnership assumed certain environmental liabilities, including ongoing environmental remediation at approximately 70 of the acquired sites and future remediation activities required by applicable federal, state or local law or regulation. Remedial action plans are in place with the applicable state regulatory agencies for the majority of these locations, including plans for soil and groundwater treatment systems at eight sites. Based on consultations with environmental engineers, the Partnership’s estimated cost of the remediation is expected to be approximately $30.0 million to be expended over an extended period of time. As a result, the Partnership recorded, on an undiscounted basis, total environmental liabilities of approximately $30.0 million.

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

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

In connection with the May 2007 acquisition of ExxonMobil’s Albany and Newburgh, New York and Burlington, Vermont terminals, the Partnership assumed certain environmental liabilities, including the remediation obligations under a proposed remedial action plan submitted by ExxonMobil to NYDEC with respect to the Albany, New York terminal. As a result, the Partnership recorded, on an undiscounted basis, total environmental liabilities of approximately $8.0 million. In June 2008, the Partnership submitted a remedial action work plan to NYDEC, implementing NYDEC’s conditional approval of the remedial action plan submitted by ExxonMobil. The Partnership responded to NYDEC’s requests for additional information and conducted pilot tests for the remediation outlined in the work plan. Based on the results of such pilot tests, the Partnership changed its estimate and reduced the environmental liability by $2.8 million during the fourth quarter ended December 31, 2008. In July 2009, NYDEC approved the remedial action work plan, and the Partnership signed a Stipulation Agreement with NYDEC to govern implementation of the approved plan. The remedial action work has been implemented pursuant to the approved work plan, and the

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Note 11. Environmental Liabilities (continued)

post-remediation stage of operation, monitoring and maintenance has commenced and is ongoing. As a result, the Partnership changed its estimate and reduced the environmental liability by $1.7 million during the second quarter ended June 30, 2011. The change in estimate, which is reflected in operating expenses in the accompanying statements of income, increased net income for the nine months ended September 30, 2011 by approximately $1.7 million, or $0.8 per limited partner unit, basic and diluted.

The following table presents a summary roll forward of the Partnership’s environmental liabilities at September 30, 2011 (in thousands):

	Balance at		Change in						Balance at
	December 31,		Estimate			Payments in			September 30,
Environmental Liability Related to:	2010		2011			2011			2011
Retail Gas Stations	$	29,766	$	—		$	(1,089	)	$	28,677
Newburgh (Warex)	1,500		—			—			1,500
Glenwood Landing and Inwood	468		—			(43		)	425
Albany	2,771		(1,697		)	(891		)	183
Total environmental liabilities	$	34,505	$	(1,697	)	$	(2,023	)	$	30,785

Current portion	$	5,535							$	2,948
Long-term portion	28,970								27,837
Total environmental liabilities	$	34,505							$	30,785

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

The General Partner has a Long-Term Incentive Plan (“LTIP”) whereby 564,242 common units were initially 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.

The Partnership granted phantom unit awards in 2009 and 2008 for which it recorded compensation expenses of approximately $55,000 and $125,000 for the three months ended September 30, 2011 and 2010, respectively, and $332,000 and $381,000 for the nine months ended September 30, 2011 and 2010, respectively, which are included in selling, general and administrative expenses in the accompanying consolidated statements of income. The total compensation cost related to the non-vested awards not yet recognized at September 30, 2011 was approximately $238,000.

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Note 12. Long-Term Incentive Plan (continued)

Repurchase Program

In May 2009, the board of directors of the General Partner authorized the repurchase of the Partnership’s common units (the “Repurchase Program”) for the purpose of meeting the General Partner’s anticipated obligations to deliver common units under the LTIP and meeting the General Partner’s obligations under existing employment agreements and other employment related obligations of the General Partner (collectively, the “General Partner’s Obligations”). Up to 445,000 of its common units in the aggregate is authorized to be acquired, 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. Through September 30, 2011, the General Partner repurchased 261,291 common units pursuant to the Repurchase Program for approximately $5.5 million.

At September 30, 2011 and December 31, 2010, common units outstanding as reported in the accompanying consolidated financial statements excluded 30,840 and 60,510 common units, respectively, held on behalf of the Partnership pursuant to its Repurchase Program and for future satisfaction of the General Partner’s Obligations.

Note 13. Fair Value Measurements

Certain of the Partnership’s assets and liabilities are measured at fair value. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants at the measurement date. The Financial Accounting Standards Board (“FASB”) established a fair value hierarchy, which prioritizes the inputs used in measuring fair value into the following three levels:

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

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

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

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Note 13. Fair Value Measurements (continued)

The following table presents those financial assets and financial liabilities measured at fair value on a recurring basis as of September 30, 2011 and December 31, 2010 (in thousands):

	Fair Value as of September 30, 2011											Fair Value as of December 31, 2010
	Total			Level 1			Level 2			Level 3		Total			Level 1			Level 2			Level 3
Assets:
Hedged inventories	$	488,905		$	—		$	488,905		$	—	$	585,323		$	—		$	585,323		$	—
Fair value of forward fixed price contracts	10,384			—			10,384			—		1,942			—			1,942			—
Swap agreements and options	428			176			252			—		211			152			59			—
Interest rate cap	175			—			175			—		—			—			—
Total	$	499,892		$	176		$	499,716		$	—	$	587,476		$	152		$	587,324		$	—

Liabilities:
Obligations on forward fixed price contracts	$	(3,373	)	$	—		$	(3,373	)	$	—	$	(9,157	)	$	—		$	(9,157	)	$	—
Swap agreements and option contracts	(238		)	(176		)	(62		)	—		(2,446		)	(150		)	(2,296		)	—
Interest rate collar and swap	(17,107		)	—			(17,107		)	—		(13,338		)	—			(13,338		)	—
Total liabilities	$	(20,718	)	$	(176	)	$	(20,542	)	$	—	$	(24,941	)	$	(150	)	$	(24,791	)	$	—

The majority of the Partnership’s derivatives outstanding are reported at fair value based market quotes that are deemed to be observable inputs in an active market for similar assets and liabilities and are considered Level 2 inputs for purposes of fair value disclosures. Specifically, the fair values of the Partnership’s financial assets and financial liabilities provided above were derived from NYMEX and New York Harbor quotes for the Partnership’s hedged inventories, forward fixed price contracts, swap agreements and option contracts and from the LIBOR rates for the Partnership’s interest rate collar, swap and interest rate cap. The Partnership has not changed its valuation techniques or inputs during the three months ended September 30, 2011.

For assets and liabilities measured on a non-recurring basis during the period, accounting guidance requires quantitative disclosures about the fair value measurements separately for each major category. See Note 10 for acquired assets and liabilities measured on a non-recurring basis during the fiscal year ended December 31, 2010. There were no assets or liabilities measured at fair value on a non-recurring basis during the quarter ended September 30, 2011.

Financial Instruments

The fair value of the Partnership’s financial instruments approximated the carrying value as of September 30, 2011 and December 31, 2010, in each case due to the short-term and the variable interest rate nature of the financial instruments.

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Note 14. Unitholders’ Equity

On March 19, 2010, the Partnership completed a public offering of 3,910,000 common units at a price of $22.75 per common unit. Net proceeds were approximately $84.6 million for the nine months ended September 30, 2010, after deducting underwriting fees and offering expenses.

On November 16, 2010, the Partnership completed a public offering of 1,955,000 common units at a price of $25.57 per common unit. Net proceeds were approximately $47.7 million, after deducting underwriting fees and offering expenses.

On February 8, 2011, the Partnership completed a public offering of 2,645,000 common units at a price of $27.60 per common unit. Net proceeds were approximately $69.6 million, after deducting underwriting fees and offering expenses.

The Partnership used the net proceeds from each of these offerings to reduce indebtedness outstanding under its Credit Agreement.

Note 15. Restructuring Charges

In July 2011, the Partnership implemented a reduction in workforce as part of its cost reduction initiatives. This reduction in workforce will result in a restructuring charge to expense of approximately $2.0 million, principally for separation and outplacement costs, of which $1.7 million was recorded in the third quarter of 2011 and included in restructuring charges in the accompanying consolidated statements of income. The remainder of approximately $0.3 million will be recorded in the fourth quarter of 2011. A total of $0.4 million has been paid through September 30, 2011.

The following table presents the changes in the Partnership’s restructuring liability, included in amounts reported as other current liabilities (in thousands):

	Severance
Balance at June 30, 2011	$	—
Restructuring expense	1,719
Cash payments	(385		)
Balance at September 30, 2011	$	1,334

Note 16. Income Taxes

Section 7704 of the Internal Revenue Code provides that publicly-traded partnerships are, as a general rule, taxed as corporations. However, an exception, referred to as the “Qualifying Income Exception,” exists under Section 7704(c) with respect to publicly-traded partnerships of which 90% or more of the gross income for every taxable year consists of “qualifying income.” Qualifying income includes income and gains derived from the transportation, storage and marketing of crude oil, natural gas and products thereof. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income.

Substantially all of the Partnership’s income is “qualifying income” for federal and state income tax purposes and, therefore, is not subject to federal and state income taxes at the partnership level. Accordingly, no provision has been made for income taxes on the qualifying income in the Partnership’s financial statements and the effective tax rate is not meaningful.

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Note 16. Income Taxes (continued)

One of the Partnership’s wholly owned subsidiaries, GMG, is a taxable entity for federal and state income tax purposes. Current and deferred income taxes are recognized on the separate earnings of GMG. The after-tax earnings of GMG are included in the earnings of the Partnership.

Note 17. Legal Proceedings

General

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

Other

In January 2011, the trustee administering the post-bankruptcy litigation trust of Lyondell Chemical Company (“Lyondell”) and certain of its affiliates brought an action against the Partnership to recover payments totaling approximately $6.0 million made to the Partnership by an affiliate of Lyondell that the trustee claims were paid shortly before the Lyondell bankruptcy and at a time when the affiliate was insolvent, allegedly permitting the avoidance or recovery of those payments pursuant to bankruptcy law. The Partnership believes that the payments were made by the affiliate in the ordinary course of both its and the Partnership’s business and as contemporaneous payment for its receipt of a volume of product of a value equivalent to the payments. The litigation is in its early stages, and the Partnership believes it has meritorious defenses. Therefore, no provision for losses has been recorded in connection with this matter.

In April 2011, seven operations personnel at the Partnership’s terminal in Chelsea, Massachusetts voted to be represented by the incumbent union representing certain other employees at this facility (“Local 25”). The Partnership will negotiate a collective bargaining agreement with Local 25 for these employees and does not believe the results of these negotiations will have a material adverse effect on its operations.

Note 18. New Accounting Standards

In May 2011, the FASB issued Accounting Standards Update (“ASU”) No. 2011-04, “Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs.” This update clarifies the application of certain existing fair value measurement guidance and expands the disclosures for fair value measurements that are estimated using significant unobservable (Level 3) inputs. This update is effective on a prospective basis for the Partnership’s annual and interim reporting periods beginning on January 1, 2012. The Partnership does not expect that adoption of this standard will have a material impact on its financial position or results of operations.

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Note 18. New Accounting Standards (continued)

In June 2011, the FASB issued ASU No. 2011-05, “Comprehensive Income (Topic 220): Presentation of Comprehensive Income.” This standard will require companies to present the components of net income and other comprehensive income either as one continuous statement or as two consecutive statements. It eliminates the option to present components of other comprehensive income as part of the statement of changes in equity. The amendments in this ASU do not change the items that must be reported in other comprehensive income or when an item of other comprehensive income must be reclassified to net income nor do the amendments affect how earnings per unit is calculated or presented. The ASU is to be applied retrospectively and is effective for interim and annual periods beginning after December 15, 2011. As this ASU only requires enhanced disclosure, the adoption of this ASU will have no effect on the Partnership’s financial position or results of operations.

Note 19. Subsequent Event

On October 19, 2011, the board of directors of the General Partner declared a quarterly cash distribution of $0.50 per unit ($2.00 per unit on an annualized basis) for the period from July 1, 2011 through September 30, 2011. On November 14, 2011, the Partnership will pay this cash distribution to its common unitholders of record as of the close of business November 3, 2011.

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

The following discussion and analysis of financial condition and results of operations of Global Partners LP should be read in conjunction with the historical consolidated financial statements of Global Partners LP and the notes thereto included elsewhere in this Quarterly Report on Form 10-Q.

Forward-Looking Statements

Some of the information contained in or incorporated by reference in this Quarterly Report on Form 10-Q may contain forward-looking statements. Forward-looking statements do not relate strictly to historical or current facts and include, without limitation, any statement that may project, indicate or imply future results, events, performance or achievements, and may contain the words “may,” “believe,” “should,” “could,” “expect,” “anticipate,” “plan,” “intend,” “estimate,” “continue,” “will likely result,” or other similar expressions. In addition, any statement made by our management concerning future financial performance (including future revenues, earnings or growth rates), ongoing business strategies or prospects, and possible actions by us are also forward-looking statements. 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, which could have an adverse effect on our financial condition, results of operations and cash available for distribution to our unitholders, 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 and renewable fuels in the areas served by our storage facilities and/or our retail gasoline business could reduce our ability to make distributions to our unitholders.

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

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

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

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

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

· Warmer weather conditions could adversely affect us.

· 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 affected by the overall forward market for refined petroleum products and renewable fuels.

· Our business could be affected by a range of issues, such as energy conservation, competition, the global economic climate, movement of products between Europe and the U.S., weekly and monthly refinery output levels, changes in local, domestic and worldwide inventory levels, seasonality and supply disruptions.

· Increases and/or decreases in the prices of refined petroleum products and renewable fuels 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.

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· 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 us.

· 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.

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

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

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

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

· Unitholders have limited voting rights and are not entitled to elect our general partner or its directors or to remove our general partner without the consent of the holders of at least 66 2/3% of the outstanding units (including units held by our general partner and its affiliates), which could lower the trading price of our common units.

· Our tax treatment depends on our status as a partnership for federal income tax purposes.

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

Additional information about risks and uncertainties that could cause actual results to differ materially from forward-looking statements is contained in Part I, Item 1A, “Risk Factors,” in our Annual Report on Form 10-K for the year ended December 31, 2010 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 of this Form 10-Q, and we expressly disclaim any obligation or undertaking to update these statements to reflect any change in our expectations or beliefs or any change in events, conditions or circumstances on which any forward-looking statement is based.

Overview

General

We own, control or have access to one of the largest terminal networks of refined petroleum products and renewable fuels in Massachusetts, Maine, Connecticut, Vermont, New Hampshire, Rhode Island, New York, New Jersey and Pennsylvania (collectively, the “Northeast”). We are one of the largest wholesale distributors of gasoline (including blendstocks such as ethanol and naphtha), distillates (such as home heating oil, diesel and kerosene), residual oil and renewable fuels to wholesalers, retailers and commercial customers in the New England states and New York. We own and supply fuel to Mobil-branded retail gas stations in New England (except Connecticut) and also supply Mobil-branded fuel to independently-owned stations. For the three and nine months ended September 30, 2011, we sold approximately $3.8 billion and $10.7 billion, respectively, of refined petroleum products, renewable fuels and small amounts of natural gas. In addition, we had revenues of approximately $15.7 million and $44.8 million for the three and nine months ended September 30, 2011, respectively, primarily from convenience store sales at our directly operated stores and gas station rental income.

We purchase our refined petroleum products and renewable fuels primarily from domestic and foreign refiners and ethanol producers, major and independent oil companies and trading companies and sell these products in two reporting segments, Wholesale and Commercial. Like most independent marketers, 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.

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Products and Operational Structure

Our products primarily include unbranded and Mobil-branded gasoline, distillates, residual oil and renewable fuels. We sell gasoline to unbranded and Mobil-branded 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 the following operating segments:

· Wholesale. This segment includes sales of gasoline (including blendstocks such as ethanol and naphtha) and diesel to unbranded and Mobil-branded retail gasoline stations and other resellers of transportation fuels and home heating oil, diesel, kerosene and residual oil to home heating oil retailers and wholesale distributors.

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

· Retail Gasoline. This segment includes sales of Mobil-branded gasoline to end users at our directly operated gas stations.

· Convenience Store. This segment includes convenience store, car wash and other ancillary sales at our directly operated stores.

· Rental Income. This segment includes rental income from our dealer leased retail gas stations.

Our business is substantially comprised of purchasing, storing, terminalling and selling refined petroleum products and renewable fuels. 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 backward market (when product prices for future deliveries are lower than current deliveries), inventories can depreciate in value and hedging costs are more expensive. For this reason, we attempt to reduce our inventories in order to minimize these effects. See Part I, Item 1A, “Risk Factors,” in our Annual Report on Form 10-K for the year ended December 31, 2010 for additional information related to commodity risk.

Outlook

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

· Our financial condition and results of operations are influenced by the overall forward market for refined petroleum products and renewable fuels, and increases and/or decreases in the prices of refined petroleum products and renewable fuels may adversely impact our financial condition, results of operations and cash available for distribution to our unitholders and the amount of borrowing available for working capital under our credit agreement, which credit agreement has borrowing base limitations and advance rates as well as access to trade credit. Results from our purchasing, storing, terminalling and selling operations are influenced by prices for refined petroleum products and renewable fuels, pricing volatility and the market for such products. Prices in the overall forward market for refined petroleum products and renewable fuels may affect our financial condition, results of operations and cash available for distribution to our unitholders. Our margins can be significantly impacted by the forward product pricing curve, often referred to as the futures market. We typically hedge our exposure to refined petroleum product and renewable fuel price moves with futures contracts and, to a lesser extent, swaps. In markets where futures prices are higher than current prices,

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referred to as contango, we may use our storage capacity to improve our margins by storing products we have purchased at lower prices in the current market for delivery to customers at higher prices in the future. In markets where futures prices are lower than current prices, referred to as backwardation, inventories can depreciate in value and hedging costs are more expensive. For this reason, we attempt to reduce our inventories in order to minimize these effects. When prices for refined petroleum products and renewable fuels rise, some of our customers may have insufficient credit to purchase supply from us at their historical purchase volumes, and their customers, in turn, may adopt conservation measures which reduce consumption, thereby reducing demand for product. Furthermore, when prices increase rapidly and dramatically, we may be unable to promptly pass our additional costs on to our customers, resulting in lower margins for us which could adversely affect our results of operations. Lastly, higher prices for refined petroleum products and renewable fuels 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 and renewable fuels 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 and renewable fuels at the then lower retail market price. Furthermore, lower prices for refined petroleum products and renewable fuels may diminish the amount of borrowings available for working capital under our working capital revolving credit facility as a result of borrowing base limitations.

· We commit substantial resources to pursuing acquisitions, although there is no certainty that we will successfully complete any acquisitions or receive the economic results we anticipate from completed acquisitions. Consistent with our business strategy, we are continuously engaged in discussions with potential sellers of terminalling, storage and/or marketing assets and related businesses. 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.

· The condition of credit markets may adversely affect our liquidity. In the recent past, world financial markets experienced a severe reduction in the availability of credit. Although we were not negatively impacted by this condition, possible negative impacts in the future could include a decrease in the availability of borrowings under our credit agreement, increased counterparty credit risk on our derivatives contracts and our contractual counterparties requiring us to provide collateral. In addition, we could experience a tightening of trade credit from our suppliers.

· 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 the 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, higher prices, new technology and alternative fuels could reduce demand for our products. Increased conservation and technological advances have adversely affected the demand for home heating oil and residual oil. Consumption of residual oil has steadily declined over the last three decades. We could face additional competition from alternative energy sources as a result of future government-mandated controls or

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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 financial condition, results of operations and cash available for distribution to our unitholders. In addition, higher prices and new technologies and alternative fuel sources, such as electric, hybrid or battery powered motor vehicles, could reduce the demand for gasoline and adversely impact our gasoline sales. A reduction in gasoline sales could have an adverse effect on our financial condition, results of operations and cash available for distribution to our unitholders.

· Changes in government usage mandates and tax credits could adversely affect the availability and pricing of ethanol, which could negatively impact our gasoline sales. Future demand for ethanol will be largely dependent upon the economic incentives to blend based upon the relative value of gasoline and ethanol, taking into consideration the Volumetric Ethanol Excise Tax Credit (the “blender’s credit”) and the EPA’s regulations on the Renewable Fuels Standard (“RFS”) program and oxygenate blending requirements. A reduction or waiver of the RFS mandate or oxygenate blending requirements or the failure to extend the blender’s credit could adversely affect the availability and pricing of ethanol, which in turn could adversely affect our future gasoline and ethanol sales.

· 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.

ExxonMobil Acquisition

On September 30, 2010, we completed our acquisition of retail gas stations and supply rights from ExxonMobil for cash consideration of approximately $202.3 million, plus the assumption of certain environmental liabilities. We acquired Mobil-branded retail gas stations located in Massachusetts, New Hampshire and Rhode Island. Additionally, we acquired the right to supply Mobil-branded fuel to such stations and to Mobil-branded stations that are owned and operated by independent dealers in these states. We outsource the day-to-day management and operations of these locations to Alliance Energy LLC, which is approximately 95% owned by members of the Slifka family, who also own our general partner. Pursuant to the brand fee agreement executed in connection with the acquisition, we also have the right to provide Mobil-branded fuel to other Mobil distributors (“Sub-jobbers”) in Massachusetts, New Hampshire, Rhode Island, Maine and Vermont.

We receive revenues from dealer leased sites pursuant to the terms of the franchise agreements from (a) rent paid by the dealers, and (b) the wholesale supply of Mobil-branded gasoline and diesel fuel sold to the dealer leased sites. From company operated sites, we receive revenues from (a) the wholesale supply of Mobil-branded gasoline and diesel fuel to these sites, (b) the sale of Mobil-branded gasoline and diesel fuel to retail end-users, and (c) convenience store, car wash and other ancillary sales. In addition, we receive revenues solely from the wholesale supply of Mobil-branded gasoline and diesel fuel to dealer owned and operated sites and to Sub-jobbers.

For further information regarding the retail gas stations and related supply rights acquired from ExxonMobil, please see Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Overview—ExxonMobil Acquisition” in our Annual Report on Form 10-K for the year ended December 31, 2010.

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Results of Operations

Evaluating Our Results of Operations

Our management uses a variety of financial and operational measurements to analyze our performance. These measurements include: (1) 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 primarily include sales of unbranded and Mobil-branded gasoline, distillates, residual oil, renewable fuels and small amounts of natural gas and convenience store sales and gas station rental income. Product costs include the cost of acquiring the refined petroleum products, renewable fuels and natural gas that we sell and all associated costs including shipping and handling costs to bring such products to the point of sale. We also look at net product margin on a per unit basis (net product margin divided by volume). Net product margin is a non-GAAP financial measure used by management and external users of our consolidated financial statements to assess our business. Net product margin should not be considered 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 primarily include sales of unbranded and Mobil-branded gasoline, distillates, residual oil, renewable fuels and small amounts of natural gas. Product costs include the cost of acquiring the refined petroleum products, renewable fuels and natural gas that we sell and all associated costs to bring such products to the point of sale.

Selling, General and Administrative Expenses

Our SG&A expenses include, among other things, marketing costs, corporate overhead, employee salaries and benefits, pension and 401(k) plan expenses, discretionary bonuses, non-interest financing costs, professional fees and information technology expenses. Employee-related expenses including employee salaries, discretionary bonuses and related payroll taxes, benefits, and pension and 401(k) plan expenses are paid by our general partner which, in turn, is reimbursed for these expenses by us.

Operating Expenses

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

Degree Day

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

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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 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 and renewable fuels, without regard to financing methods and capital structure; and

· the viability of acquisitions and capital expenditure projects and the overall rates of return of alternative investment opportunities.

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

Distributable Cash Flow

Distributable cash flow is an important non-GAAP financial measure for our limited partners since it serves as an indicator of our success in providing a cash return on their investment. Distributable cash flow means our net income plus depreciation and amortization minus maintenance capital expenditures, as well as adjustments to eliminate items approved by the audit committee of the board of directors of our general partner that are extraordinary or non-recurring in nature and that would otherwise increase distributable cash flow. Specifically, this financial measure indicates to investors whether or not we have generated sufficient earnings on a current or historic level that can sustain or support an increase in our quarterly cash distribution. Distributable cash flow is a quantitative standard used by the investment community with respect to publicly traded partnerships. Distributable cash flow should not be considered as an alternative to net income, 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.

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Three and Nine Months Ended September 30, 2011 and 2010

During the three and nine months ended September 30, 2011, we experienced the following events:

· Refined petroleum product prices were significantly higher during the three and nine months ended September 30, 2011 compared to the same periods in 2010.

· Our aggregate volume of product sold increased by approximately 66% and 52% for the three and nine months ended September 2011, respectively, compared to the same periods in 2010, due to an increase in supply activity, strong demand for blendstocks, primarily ethanol, and the growth in our gasoline business as a result of our 2010 acquisitions.

· Temperatures for the three and nine months ended September 30, 2011 were 29% and 17% colder than the comparable periods in 2010.

· We increased our reserve for bad debts by approximately $1.8 million during the first nine months of 2011, substantially due to specific risks related to one customer, compared to $370,000 for the first nine months of 2010.

· We reduced our workforce by approximately 10% which resulted in restructuring charges of approximately $1.7 million for the three and nine months ended September 30, 2011.

· Our interest expense increased by 34% and 64% for the three and nine months ended September 30, 2011, respectively, primarily to additional borrowing costs and to higher refined petroleum product prices.

· We believe heating oil conservation and conversions to natural gas continued during the three and nine months ended September 30, 2011.

· Our operating expenses increased by $9.0 million and $26.0 million for the three and nine month ended September 30, 2011, respectively, compared to the same periods in 2010 primarily due to the operations of the retail gas stations we acquired from ExxonMobil in September 2010.

· We believe our margins for the three and nine months ended September 30, 2011 were impacted due to less favorable market conditions and fewer advantageous purchasing opportunities in our distillates business and to a backward forward product pricing curve in our wholesale gasoline business.

· Our margins for the nine months ended September 30, 2011 were also affected by a variety of other factors, such as movement of products between Europe and the U.S., weekly and monthly refinery output levels, changes in local, domestic and worldwide inventory levels, seasonality and supply disruptions.

The following table provides the prices of and percentage increases (decreases) in refined petroleum product and natural gas prices at the end of the first three quarters in 2011 as compared to the comparable quarters in 2010:

	Heating		Residual	Natural
	Oil	Gasoline	Oil	Gas
	$per	$per	$per	$per gallon
Period:	gallon(1)	gallon(1)	gallon(2)	equivalent(3)

At March 31, 2010	$2.16	$2.31	$1.76	$0.63
At March 31, 2011	$3.09	$3.11	$2.45	$0.73
Change	43%	35%	39%	16%

At June 30, 2010	$1.98	$2.06	$1.61	$0.75
At June 30, 2011	$2.93	$3.03	$2.51	$0.73
Change	48%	47%	56%	(3%)

At September 30, 2010	$2.24	$2.04	$1.74	$0.62
At September 30, 2011	$2.79	$2.63	$2.29	$0.62
Change	25%	29%	32%	—

(1) Source: New York Mercantile Exchange (closing price)

(2) Source: Platts Oilgram Price Report (6-1% New York Harbor; average)

(3) Source: Platts Gas Daily Report (Tennessee zone delivered)

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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						Nine Months Ended
	September 30,						September 30,
	2011			2010			2011			2010
Net income	$	1,858		$	551		$	9,303		$	21,099

Net income per diluted limited partner unit (1)	$	0.08		$	0.03		$	0.41		$	1.28

EBITDA (2)	$	18,670		$	12,526		$	58,956		$	50,473

Distributable cash flow (3)	$	8,598		$	5,433		$	30,289		$	33,498

Wholesale Segment:
Volume (gallons)	1,170,528			715,362			3,428,816			2,288,428
Sales
Gasoline (4)	$	2,746,585		$	1,066,764		$	6,982,846		$	2,929,257
Distillates	712,939			376,878			2,889,373			1,778,730
Residual oil	1,195			8,505			24,880			28,902
Total	$	3,460,719		$	1,452,147		$	9,897,099		$	4,736,889
Net product margin (5)
Gasoline	$	26,779		$	16,412		$	76,123		$	48,333
Distillates	10,153			18,440			36,336			58,920
Residual oil	1,245			1,864			4,756			7,154
Total	$	38,177		$	36,716		$	117,215		$	114,407
Commercial Segment:
Volume (gallons)	105,249			54,521			307,091			176,633
Sales (4)	$	289,299		$	94,692		$	787,117		$	309,396
Net product margin (5)	$	9,268		$	2,318		$	27,642		$	10,040
All Other:
Sales (4)	$	15,747		$	—		$	44,769		$	—
Net product margin (5)	$	7,938		$	—		$	23,506		$	—
Combined sales and net product margin:
Sales	$	3,765,765		$	1,546,839		$	10,728,985		$	5,046,285
Net product margin (5)	$	55,383		$	39,034		$	168,363		$	124,447
Depreciation allocated to cost of sales	(6,104		)	(3,939		)	(18,263		)	(9,623		)
Combined gross profit	$	49,279		$	35,095		$	150,100		$	114,824

Weather conditions:
Normal heating degree days	96			96			3,750			3,750
Actual heating degree days	44			34			3,690			3,161
Variance from normal heating degree days	(54%		)	(65%		)	(2%		)	(16%		)
Variance from prior period actual heating degree days	29%			(68%		)	17%			(17%		)

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

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

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

(4) On September 30, 2010, we completed our acquisition of retail gas stations and supply rights from ExxonMobil (see Note 10 of Notes to Consolidated Financial Statements). As these assets were not in place for a substantial portion of the quarter ended September 30, 2010, the above results are not directly comparable for periods prior to September 2010.

(5) 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						Nine Months Ended
	September 30,						September 30,
	2011			2010			2011			2010
Reconciliation of net income to EBITDA:
Net income	$	1,858		$	551		$	9,303		$	21,099
Depreciation and amortization and amortization of deferred financing fees	8,865			6,087			26,175			14,661
Interest expense	7,947			5,888			23,478			14,326
Income tax expense	—			—			—			387
EBITDA	$	18,670		$	12,526		$	58,956		$	50,473

Reconciliation of net cash provided by (used in) operating activities to EBITDA:
Net cash provided by (used in) operating activities	$	52,505		$	(83,522	)	$	(6,779	)	$	(32,958	)
Net changes in operating assets and liabilities and certain non-cash items	(41,782		)	90,160			42,257			68,718
Interest expense	7,947			5,888			23,478			14,326
Income tax expense	—			—			—			387
EBITDA	$	18,670		$	12,526		$	58,956		$	50,473

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						Nine Months Ended
	September 30,						September 30,
	2011			2010			2011			2010
Reconciliation of net income to distributable cash flow:
Net income	$	1,858		$	551		$	9,303		$	21,099
Depreciation and amortization and amortization of deferred financing fees	8,865			6,087			26,175			14,661
Amortization of routine bank refinancings (1)	(932		)	—			(2,508		)	—
Maintenance capital expenditures	(1,193		)	(1,205		)	(2,681		)	(2,262		)
Distributable cash flow	$	8,598		$	5,433		$	30,289		$	33,498

Reconciliation of net cash provided by (used in) operating activities to distributable cash flow:
Net cash provided by (used in) operating activities	$	52,505		$	(83,522	)	$	(6,779	)	$	(32,958	)
Net changes in operating assets and liabilities and certain non-cash items	(41,782		)	90,160			42,257			68,718
Amortization of routine bank refinancings (1)	(932		)	—			(2,508		)	—
Maintenance capital expenditures	(1,193		)	(1,205		)	(2,681		)	(2,262		)
Distributable cash flow	$	8,598		$	5,433		$	30,289		$	33,498

(1) Commencing with the quarter ended March 31, 2011, our calculation of distributable cash flow excludes non-cash amortization of deferred financing fees related to routine bank refinancings. Amortization of deferred financing fees in connection with our expansion-related activities will continue to be included. We believe that this provides a more conservative methodology to this non-GAAP financial measure. Had this methodology been used previously, it would not have affected distribution decisions or the outcome of the recent conversion of subordinated units to common units. Had this methodology been used for the three and nine months ended September 30, 2010, distributable cash flow would have been lower by approximately $0.8 million and $1.8 million, respectively.

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Consolidated Results

Our total sales for the three months ended September 30, 2011 increased by $2,219.0 million, or 143%, to $3,765.8 million compared to $1,546.8 million for the same period in 2010. The increase was primarily due to higher refined petroleum product prices for the third quarter of 2011 compared to the third quarter of 2010, an increase in supply activity and strong demand for blendstocks, primarily ethanol and an increase in volume sold as a result of our September 2010 acquisition of retail gas stations and supply rights from ExxonMobil (see Note 10 of Notes to Consolidated Financial Statements). Our aggregate volume of product sold increased by approximately 506 million gallons, or 66%, to 1,276 million gallons and primarily includes increases of approximately 424 million gallons in gasoline as a result of our acquisition of retail gas stations and supply rights, 68 million gallons in distillates, due primarily to colder temperatures during the third quarter of 2011 compared to the third quarter of 2010 and an increase in non-weather related distillates, and 10 million gallons in residual oil. Our gross profit for the third quarter of 2011 was $49.3 million, an increase of $14.2 million, or 40%, compared to $35.1 million for the third quarter of 2010, due primarily to the addition of our retail gas stations and supply rights.

Our total sales for the nine months ended September 30, 2011 increased by $5,682.7 million, or 113%, to $10,729.0 million compared to $5,046.3 million for the same period in 2010. The increase was primarily due to higher refined petroleum product prices for the first nine months of 2011 compared to the same period in 2010 and to an increase in volume sold as a result of our 2010 acquisitions (in June of three refined petroleum products terminals located in Newburgh, New York and in September of retail gas stations and supply rights from ExxonMobil, collectively our “2010 Acquisitions”). Our aggregate volume of product sold increased by approximately 1,271 million gallons, or 52%, to 3,736 million gallons. The increase in volume sold primarily includes increases of approximately 1,064 million gallons in gasoline due primarily to our 2010 Acquisitions, 169 million gallons in distillates, due primarily to colder temperatures during the first nine months of 2011 compared to the same period in 2010 and an increase in non-weather related distillates, and 17 million gallons in residual oil. The number of actual heating degree days increased 17% to 3,690 for the first nine months of 2011 compared to 3,161 for the same period in 2010. Our gross profit for the first nine months of 2011 was $150.1 million, an increase of $35.3 million, or 31%, compared to $114.8 million for same period in 2010, due primarily to our 2010 Acquisitions.

Wholesale Segment

Gasoline. Wholesale gasoline sales for the three months ended September 30, 2011 were $2,746.5 million compared to $1,066.8 million for the same period in 2010. During the first nine months of 2011, wholesale gasoline sales were $6,982.8 million compared to $2,929.3 million for the same period in 2010. The increases of $1,679.7 million, or 157%, and $4,053.5 million, or 138%, for the three and nine months ended September 30, 2011, respectively, compared to the same periods in 2010, were due primarily to higher gasoline prices, an increase in volume sold and the addition of sales of Mobil-branded fuel to Sub-jobbers pursuant to our brand fee agreement (see “—ExxonMobil Acquisition”). The increases in volume sold were attributable to an increase in supply activity, strong demand for blendstocks, primarily ethanol, and, for the first nine months of 2011, our 2010 Acquisitions. Our net product margin from gasoline sales increased by $10.4 million to $26.8 million for the three months ended September 30, 2011 and by $27.8 million to $76.1 million for the nine months ended September 30, 2011 compared to $16.4 million and $48.3 million for the respective periods in 2010. Despite these increases, which were primarily attributable to our 2010 Acquisitions, our net product margins for gasoline were adversely impacted for the three and, to a lesser extent, the nine months ended September 30, 2011 due to less favorable market conditions, primarily a backward forward product pricing curve.

Distillates. Wholesale distillate sales for the three months ended September 30, 2011 were $713.0 million compared to $376.8 million for the same period in 2010. During the first nine months of 2011, wholesale distillate sales were $2,889.4 million compared to $1,778.7 million for the same period in 2010. The increases of $336.2 million, or 89%, and $1,110.7 million, or 62%, respectively, were due to increases in refined petroleum product prices and in volume sold. Despite increases in volume sold in 2011 compared to 2010 due to colder temperatures, our net product margin from distillate sales decreased by $8.3 million, or 45%, to $10.2 million for the three months ended September 30, 2011 and by $22.6 million, or 38%, to $36.3 million for the nine months ended September 30, 2011 compared to the same periods in 2010. These decreases were primarily due to less favorable market conditions and fewer advantageous purchasing opportunities.

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Residual Oil. Wholesale residual oil sales for the three months ended September 30, 2011 were $1.2 million compared to $8.5 million for the same period in 2010. During the first nine months of 2011, wholesale residual sales were $24.9 million compared to $28.9 million for the same period in 2010. The decreases of $7.3 million, or 86%, and $4.0 million, or 14%, respectively, were due to decreases in volume sold. Our net product margin contribution from residual oil sales decreased by $0.6 million to $1.2 million for the three months ended September 30, 2011 and by $2.4 million to $4.8 million for the nine months ended September 30, 2011 compared to the same periods in 2010.

Commercial Segment

Our total commercial segment sales increased by approximately $194.6 million, or 205%, to $289.3 million and by $477.7 million, or 154%, to $787.1 million for the three and nine months ended September 30, 2011, respectively, compared to the same periods in 2010, primarily due to the addition of our directly operated gas stations. Commercial residual oil sales increased by approximately 104% and 64% of total commercial sales for the three and nine months ended September 30, 2011, respectively, due to increases in refined petroleum product prices and to increases in volume sold compared to the same periods in 2010.

Our total commercial segment volume increased by approximately 50.7 million gallons, or 93%, and by 130 million gallons, or 74%, for the three and nine months ended September 30, 2011, respectively, compared to the same periods in 2010, primarily due to the addition of our directly-operated gas stations. Residual oil accounted for approximately 43% and 59% of total commercial volume sold for the three months ended September 30, 2011 and 2010, respectively, and approximately 39% and 24% for the nine months ended September 30, 2011 and 2010, respectively. Gasoline accounted for approximately 25% and 5% of total commercial volume sold for the three months ended September 30, 2011 and 2010, respectively, and approximately 24% and 4% for the nine months ended September 30, 2011 and 2010, respectively. Distillates and natural gas accounted for the remainder of the total volume sold.

Selling, General and Administrative Expenses

SG&A expenses were flat at $17.2 million for the three months ended September 30, 2011 and 2010. During the quarter ended September 30, 2011, we had increases of $1.1 million in management costs associated with the retail gas stations and supply rights acquired from ExxonMobil and $1.0 million in bank fees and amortization of deferred financing fees, offset by decreases of $1.2 million in professional and consulting fees, $0.7 million in incentive compensation and $0.2 million in various other SG&A expenses. The $1.0 million increase in bank fees and amortization of deferred financing fees was largely due to increased letter of credit fees related to the growth in our gasoline business and higher refined petroleum product prices, and to the expansion of our credit facilities.

SG&A expenses increased by $9.4 million, or 20%, to $57.1 million for the nine months ended September 30, 2011 compared to $47.7 million for the same period in 2010. The increase was primarily due to increases of $4.7 million in management costs associated with the retail gas stations and supply rights acquired from ExxonMobil, $3.9 million in bank fees and amortization of deferred financing fees, $1.4 million in bad debt, $1.1 million in overhead (including information technology, natural gas personnel and project management) and $1.6 million in various other SG&A expenses. The $3.9 million increase in bank fees and amortization of deferred financing fees was largely due to increased letter of credit fees related to the growth in our gasoline business and higher refined petroleum product prices, and to the expansion of our credit facilities. The overall increase was offset by a decrease of approximately $2.6 million in professional and consulting fees and $0.7 million in incentive compensation.

Operating Expenses

Operating expenses increased by $9.0 million, or 86%, to $19.4 million for the three months ended September 30, 2011 compared to $10.4 million for the same period in 2010. The increase was primarily due to $8.3 million in additional costs related to the operations of the retail gas stations acquired from ExxonMobil and $0.7 million in various other operating expenses. The $8.3 million in costs related to the retail gas stations primarily included $2.2 million in staff costs reimbursed to our management company, Alliance, $1.6 million in credit card fees, $1.5 million in service station direct expenses, $1.4 million in various maintenance expenses, $0.8 million in property taxes and $0.8 million in rent expense.

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Operating expenses increased by $26.0 million, or 90%, to $54.9 million for the nine months ended September 30, 2011 compared to $28.9 million for the same period in 2010. The increase was primarily due to $24.9 million in additional costs related to the operations of the retail gas stations acquired from ExxonMobil, $1.1 million in costs related to our Revere, Massachusetts terminal, $0.9 million in costs related to our Newburgh, New York (Warex) terminal, $0.7 million in costs related to the Albany, New York terminal and $0.1 million in other operating expenses. For the nine months ended September 30, 2011, the increase in operating expenses was partially offset by a decrease of approximately $1.7 million related to a change in estimate of our remediation obligations with respect to the Albany, New York terminal (see Note 11 of Notes to Consolidated Financial Statements). The $24.9 million in costs related to the retail gas stations primarily included $6.7 million in staff costs reimbursed to our management company, Alliance, $4.9 million in service station direct expenses, $4.2 million in credit card fees, $4.1 million various maintenance expenses, $2.6 million in property taxes and $2.4 million in rent expense.

Restructuring Charges

During the third quarter of 2011, we reduced our workforce by approximately 10% which resulted in restructuring charges of approximately $1.7 million for the three and nine months ended September 30, 2011. These restructuring charges consist principally of severance and outplacement costs for terminated employees. The remainder of approximately $0.3 million will be recorded in the fourth quarter of 2011. A total of $0.4 million has been paid through September 30, 2011. See Note 15 of Notes to Consolidated Financial Statements.

Interest Expense

Interest expense for the three months ended September 30, 2011 increased by $2.0 million, or 34%, to $7.9 million compared to $5.9 million for same period in 2010. Interest expense for the nine months ended September 30, 2011 increased by $9.2 million, or 64%, to $23.5 million compared to $14.3 million for the same period in 2010. We attribute the increase primarily to additional borrowing costs as a result of our 2010 Acquisitions and to higher average balances on our working capital revolving credit facility from carrying higher average dollar values of inventories and accounts receivable reflecting increased refined petroleum product prices. In addition, the costs of borrowings under the credit agreement were increased in connection with the May and August 2010 amendments to the credit agreement.

Liquidity and Capital Resources

Liquidity

Our primary liquidity needs are to fund our working capital requirements, capital expenditures and distributions. Cash generated from operations and our working capital revolving credit facility provide our primary sources of liquidity. Working capital increased by $24.4 million to $470.3 million at September 30, 2011 compared to $445.9 million at December 31, 2010.

On February 8, 2011, we completed a public offering of 2,645,000 common units at a price of $27.60 per common unit. Net proceeds were approximately $69.6 million, after deducting underwriting fees and offering expenses. We used the net proceeds to reduce indebtedness outstanding under our credit agreement.

On February 14, 2011, we paid a cash distribution to our common and subordinated unit holders and our general partner of approximately $9.7 million for the fourth quarter of 2010. On May 13, 2011, we paid a cash distribution to our common unit holders and our general partner of approximately $11.0 million for the first quarter of 2011. On August 12, 2011, we paid a cash distribution to our common unit holders and our general partner of approximately $11.0 million for the second quarter of 2011. On October 19, 2011, the board of directors of our general partner declared a quarterly cash distribution of $0.50 per unit for the period from July 1, 2011 through September 30, 2011 ($2.00 per unit on an annualized basis) to our common unit holders of record as of the close of business November 3, 2011. We expect to pay the cash distribution of approximately $11.0 million on November 14, 2011.

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Capital Expenditures

Our operations require investments to expand, upgrade and enhance existing operations and to meet environmental and operations regulations. We categorize our capital requirements as either maintenance capital expenditures or expansion capital expenditures. Maintenance capital expenditures represent capital expenditures to repair or replace partially or fully depreciated assets to maintain the operating capacity of, or revenues generated by, existing assets and extend their useful lives. Maintenance capital expenditures include expenditures required to maintain equipment reliability, tankage and pipeline integrity and safety and to address certain environmental regulations. We anticipate that maintenance capital expenditures will be funded with cash generated by operations. We had approximately $2.7 million and $2.3 million in maintenance capital expenditures for the nine months ended September 30, 2011 and 2010, respectively, which are included in capital expenditures in the accompanying consolidated statements of cash flows. Repair and maintenance expenses associated with existing assets that are minor in nature and do not extend the useful life of existing assets are charged to operating expenses as incurred.

Expansion capital expenditures include expenditures to acquire assets to grow our business or expand our existing facilities, such as projects that increase our operating capacity or revenues by increasing tankage, diversifying product availability at various terminals and adding terminals. We have the ability to fund our expansion capital expenditures through cash from operations or our credit agreement or by issuing additional equity. We had approximately $4.8 million and $253.6 million in expansion capital expenditures for the nine months ended September 30, 2011 and 2010, respectively. Specifically, for the nine months ended September 30, 2011, expansion capital expenditures included $1.6 million in costs related to information technology, including increases in storage and computing capacity and hardware and software related to our branded gasoline business, $1.3 million in costs related to our Albany, New York terminal including $0.4 million in costs associated with converting certain storage tanks for the handling of crude oil, $0.8 million in costs related to our Newburgh, New York facilities, $0.5 million in bio-fuel conversion costs at our Providence, Rhode Island terminal, $0.3 million in gas station equipment, and $0.3 million in other expansion capital expenditures which are included in capital expenditures in the accompanying consolidated statements of cash flows.

Comparatively, for the nine months ended September 30, 2010, expansion capital expenditures included approximately $248.3 million in acquisition costs including $202.3 million for the purchase of retail gas stations and supply rights from ExxonMobil and $46.0 million for the acquisition of three refined petroleum products terminals in Newburgh, New York. In addition, we had $5.3 million in expansion capital expenditures which consisted of $4.1 million in expenditures related to our Albany, New York terminal and rail ethanol expansion project, $0.5 million in bio-fuel conversion costs at our Chelsea, Massachusetts terminal and $0.7 million in other expansion capital expenditures, which are included in capital expenditures in the accompanying consolidated statements of cash flows. The $4.1 million in expenditures related to our Albany terminal include costs related to our program to bring previously out-of-permit tanks back online, the installation of a marine vapor recovery system to allow for barge/vessel loading of gasoline and ethanol and the effort to convert two distillate storage tanks to gasoline.

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

Cash Flow

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

	Nine Months Ended
	September 30,
	2011			2010
Net cash used in operating activities	$	(6,779	)	$	(32,958	)
Net cash used in investing activities	$	(6,516	)	$	(255,856	)
Net cash provided by financing activities	$	21,806		$	292,744

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

Net cash used in operating activities was $6.8 million for the nine months ended September 30, 2011 compared to $33.0 million for the nine months ended September 30, 2010, for a period-over-period decrease in cash used in operating activities of $26.2 million.

During the nine months ended September 30, 2011, we experienced increases in refined petroleum product prices and we funded additional working capital requirements due to our 2010 Acquisitions. For the nine months ended September 30, 2011, we had decreases in the carrying values of accounts receivable of $113.0 million and accounts payable of $80.8 million, reflecting seasonal changes, and an increase in the carrying value of inventories of $12.0 million due to higher prices and carrying lower levels of inventories. In 2010, comparatively, we had decreases in the carrying values of accounts receivable of $31.5 million and account payable of $34,000 and an increase in inventories of $65.9 million due to higher refined petroleum product prices. The overall decrease in cash used in operating activities also reflects the period-over-period decrease in net income of $11.8 million.

In addition, through the use of regulated exchanges or derivatives, we maintain a position that is substantially hedged with respect to our inventories. Specifically, for the nine months ended September 30, 2011, the contracts supporting our forward fixed price hedge program required margin payments of $14.2 million to the NYMEX due to market direction, compared to $9.9 million for the nine months ended September 30, 2010.

Net cash used in investing activities was $6.5 million for the nine months ended September 30, 2011 and included $2.7 million in maintenance capital expenditures and $4.8 million in expansion capital expenditures consisting of $1.6 million in costs related to information technology, including increases in storage and computing capacity and hardware and software related to our branded gasoline business, $1.3 million in costs related to our Albany, New York terminal including $0.4 million in costs associated with converting certain storage tanks for the handling of crude oil, $0.8 million in costs related to our Newburgh, New York facilities, $0.5 million in bio-fuel conversion costs at our Providence, Rhode Island terminal, $0.3 million in gas station equipment, and $0.3 million in other expansion capital expenditures. Net cash used in investing activities was offset by approximately $1.0 million in proceeds from the sale of property and equipment.

Comparatively, net cash used in investing activities was $255.8 million for the nine months ended September 30, 2010 and included $2.3 million in maintenance capital expenditures and $253.6 million in expansion capital expenditures. The $253.6 million included approximately $248.3 million in acquisition costs including $202.3 million for the purchase of retail gas stations and supply rights from ExxonMobil and $46.0 million for the acquisition of three refined petroleum products terminals in Newburgh, New York. In addition, we had $5.3 million in expansion capital expenditures which consisted of $4.1 million in expenditures related to our Albany, New York terminal and rail ethanol expansion project, $0.5 million in bio-fuel conversion costs at our Chelsea, Massachusetts terminal and $0.7 million in other expansion capital expenditures, which are included in capital expenditures in the accompanying consolidated statements of cash flows. The $4.1 million in expenditures related to our Albany terminal include costs related to our program to bring previously out-of-permit tanks back online, the installation of a marine vapor recovery system to allow for barge/vessel loading of gasoline and ethanol and the effort to convert two distillate storage tanks to gasoline.

Net cash provided by financing activities was $21.8 million for the nine months ended September 30, 2011 and primarily included $69.6 million in net proceeds from our February 2011 public offering of common units, offset by $31.8 million in cash distributions to our common and subordinated unit holders and our general partner, $14.7 million in net payments on our credit facilities, $0.7 million in repurchased units held for tax obligations related to units distributed under the LTIP, and $0.6 million in the repurchase of common units pursuant to our repurchase program for future satisfaction of our general partner’s obligations.

Comparatively, net cash provided by financing activities was $292.7 million for the nine months ended September 30, 2010 and included net borrowings on our credit facilities of $231.9 million and $84.6 million in net proceeds from our public offering of common units, offset by $23.3 million in cash distributions to our common and subordinated unit holders and our general partner and $0.4 million in repurchased units held for tax obligations related to units distributed under the LTIP.

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Credit Agreement

On January 26, 2011, we requested an increase in the working capital revolving credit facility in an amount equal to $100.0 million, and on February 11, 2011, certain lenders under the credit agreement committed to the $100.0 million increase which increased the total available commitments under the credit agreement to $1.25 billion. We repay amounts outstanding and reborrow funds based on our working capital requirements and, therefore, classify as a current liability the portion of the working capital revolving credit facility we expect to pay down during the course of the year. The long-term portion of the working capital revolving credit facility is the amount we expect to be outstanding during the entire year. The credit agreement will mature on May 14, 2014.

There are two 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 $900.0 million; and

· a $350.0 million revolving credit facility to be used for acquisitions and general corporate purposes.

In addition, the credit agreement has an accordion feature whereby we may request on the same terms and conditions of our then existing credit agreement, provided no Event of Default (as defined in the credit agreement) then exists, an increase to the revolving credit facility, the working capital revolving credit facility, or both, by up to another $100.0 million, for a total credit facility of up to $1.35 billion. Any such request for an increase by us must be in a minimum amount of $5.0 million, and the revolving credit facility may not be increased by more than $50.0 million. We cannot provide assurance, however, that our lending group will agree to fund any request by us for additional amounts in excess of the total available commitments of $1.25 billion.

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

Commencing May 14, 2010, borrowings under the working capital revolving credit facility bear interest at (1) the Eurodollar rate plus 2.50% to 3.00%, (2) the cost of funds rate plus 2.50% to 3.00%, or (3) the base rate plus 1.50% to 2.00%, each depending on the pricing level provided in the credit agreement, which in turn depends upon the Utilization Amount (as defined in the credit agreement).

During the period from May 14, 2010 through September 7, 2010, borrowings under the revolving credit facility bore interest at (1) the Eurodollar rate plus 3.00% to 3.25%, (2) the cost of funds rate plus 3.00% to 3.25%, or (3) the base rate plus 2.00% to 2.25%, each depending on the pricing level provided in the credit agreement, which in turn depended upon the Combined Senior Secured Leverage Ratio (as defined in the credit agreement). Commencing September 8, 2010, borrowings under the revolving credit facility bear interest at (1) the Eurodollar rate plus 3.00% to 3.875%, (2) the cost of funds rate plus 3.00% to 3.875%, or (3) the base rate plus 2.00% to 2.875%, each depending on the pricing level provided in the Credit Agreement, which in turn depends upon the Combined Total Leverage Ratio (as defined in the credit agreement).

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The average interest rates for the credit agreement were 4.0% and 4.1% for the three months ended September 30, 2011 and 2010, respectively, and 4.0% and 3.8% for the nine months ended September 30, 2011 and 2010, respectively.

We incur a letter of credit fee of 2.50% - 3.00% per annum for each letter of credit issued. In addition, we incur a commitment fee on the unused portion of each facility under the credit agreement equal to 0.50% per annum.

As of September 30, 2011, we had total borrowings outstanding under the credit agreement of $772.0 million, including $220.0 million outstanding on our revolving credit facility. In addition, we had outstanding letters of credit of $167.3 million. Subject to borrowing base limitations, the total remaining availability for borrowings and letters of credit at September 30, 2011 and December 31, 2010 was $310.7 million and $252.6 million, respectively.

The credit agreement imposes financial covenants that require us to maintain certain minimum working capital amounts, capital expenditure limits, a minimum EBITDA, a minimum combined interest coverage ratio, a maximum senior secured leverage ratio and a maximum total leverage ratio. On July 19, 2011, we entered into a second amendment to the credit agreement which amended the credit agreement and modified certain financial covenants. We were in compliance with the foregoing covenants at September 30, 2011. The credit agreement also contains a representation whereby there can be no event or circumstance, either individually or in the aggregate, that has had or could reasonably be expected to have a Material Adverse Effect (as defined in the credit agreement). In addition, the credit agreement limits distributions by us to our unit holders to the amount of our Available Cash (as defined in the partnership agreement).

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 is comprised of the following institutions: Bank of America, N.A.; JPMorgan Chase Bank, N.A.; Wells Fargo Bank, N.A.; Societe Generale; Standard Chartered Bank; RBS Citizens, National Association; BNP Paribas; Cooperative Centrale Raiffeisen-Boerenleenbank B.A., “Rabobank Nederland” New York Branch; Sovereign Bank; Credit Agricole Corporate and Investment Bank; Keybank National Association; Toronto Dominion (New York); RB International Finance (USA) LLC (formerly known as RZB Finance LLC); Royal Bank of Canada; Raymond James Bank, FSB; Barclays Bank plc; Webster Bank National Association; Natixis, New York Branch; DZ Bank AG Deutsche Zentral-Genossenschaftsbank Frankfurt Am Main; Branch Banking & Trust Company; and Sumitomo Mitsui Banking Corporation.

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements.

Critical Accounting Policies and Estimates

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

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

The significant accounting policies and estimates that we have adopted and followed in the preparation of our consolidated financial statements are detailed in Note 2 of Notes to Consolidated Financial Statements, “Summary of Significant Accounting Policies” included in our Annual Report on Form 10-K for the year ended December 31, 2010. 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.

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Item 3. Quantitative and Qualitative Disclosures about Market Risk

Market risk is the risk of loss arising from adverse changes in market rates and prices. The principal market risks to which we are exposed are interest rate risk and commodity risk. We utilize an interest rate collar, a swap and an interest rate cap to manage exposure to interest rate risk and various derivative instruments to manage exposure to commodity risk.

Interest Rate Risk

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

On January 26, 2011, the total available commitments under our credit agreement were increased to $1.25 billion. Please read Item 2, “Management’s Discussion and Analysis—Liquidity and Capital Resources—Credit Agreement” for information on interest rates related to our borrowings.

As of September 30, 2011, we had total borrowings outstanding under the credit agreement of $772.00 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 $7.7 million annually, assuming, however, that our indebtedness remained constant throughout the year.

On September 29, 2008, we executed a zero premium interest rate collar with a major financial institution. The collar, which became effective on October 2, 2008 and expires on October 2, 2013, is used to hedge the variability in cash flows in monthly interest payments made on our $100.0 million one-month LIBOR-based borrowings on the working capital revolving credit facility (and subsequent refinancings thereof) due to changes in the one-month LIBOR rate. Under the 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 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 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 September 30, 2011, the one-month LIBOR rate of 0.22% was lower than the floor rate. As a result, we will remit to the financial institution the difference between the floor rate and the current rate which amounted to approximately $200,000.

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

In addition, on April 8, 2011, we executed an interest rate cap with a major financial institution. The rate cap, which became effective on April 13, 2011 and expires on April 13, 2016, is used to hedge the variability in interest payments due to changes in the one-month LIBOR rate above 5.5% with respect to $100.0 million of one-month LIBOR-based borrowings on the working capital revolving credit facility.

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

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Commodity Risk

We hedge our exposure to price fluctuations with respect to refined petroleum products and blendstocks in storage and expected purchases and sales of these commodities. The derivative instruments utilized consist primarily of futures contracts traded on the NYMEX and the CME and over-the-counter transactions, including swap agreements entered into with established financial institutions and other credit-approved energy companies. Our policy is generally to purchase only products for which we have a market and to structure our sales contracts so that price fluctuations do not materially affect our profit. While our policies are designed to minimize market risk, as well as inherent basis risk, exposure to fluctuations in market conditions remains. Except for the controlled trading program discussed below, we do not acquire and hold futures contracts or other derivative products for the purpose of speculating on price changes that might expose us to indeterminable losses.

While we seek to maintain a position that is substantially balanced within our product purchase activities, we may experience net unbalanced positions for short periods of time as a result of variances in daily sales and transportation and delivery schedules as well as 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 and blendstocks 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 and renewable fuels. Any hedge ineffectiveness is reflected in our results of operations. We utilize regulated exchanges, including the NYMEX and the CME, which are regulated exchanges for energy products that it trades, thereby reducing potential delivery and supply risks. Generally, our practice is to close all exchange positions rather than to make or receive physical deliveries. With respect to other energy products such as ethanol, which may not have a correlated exchange contract, we enter into derivative agreements with counterparties that we believe have a strong credit profile, in order to hedge market fluctuations and/or lock-in margins relative to our commitments.

At September 30, 2011, the fair value of all of our commodity risk derivative instruments and the change in fair value that would be expected from a 10% price increase or decrease are shown in the table below (in thousands):

	Fair Value at		Gain (Loss)
	September 30, 2011		Effect of 10% Price Increase			Effect of 10% Price Decrease
Futures contracts	$	35,158	$	(52,102	)	$	52,102
Swaps, options and other, net	190		(397		)	1,747
	$	35,348	$	(52,499	)	$	53,849

The fair values of the futures contracts are based on quoted market prices obtained from the NYMEX and the CME. The fair value of the swaps and option contracts are estimated based on quoted prices from various sources such as independent reporting services, industry publications and brokers. These quotes are compared to the contract price of the swap, which approximates the gain or loss that would have been realized if the contracts had been closed out at September 30, 2011. For positions where independent quotations are not available, an estimate is provided, or the prevailing market price at which the positions could be liquidated is used. All hedge positions offset physical exposures to the physical market; none of these offsetting physical exposures are included in the above table. Price-risk sensitivities were calculated by assuming an across-the-board 10% increase or decrease in price regardless of term or historical relationships between the contractual price of the instruments and the underlying commodity price. In the event of an actual 10% change in prompt month prices, the fair value of our derivative portfolio would typically change less than that shown in the table due to lower volatility in out-month prices. We have a daily margin requirement to maintain a cash deposit with our brokers based on the prior day’s market results on open futures contracts. The balance of this deposit will fluctuate based on our open market positions and the commodity exchange’s requirements. The brokerage margin balance was $38.4 million at September 30, 2011.

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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 unit holders. 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 two clearing brokers, both major financial institutions, for all NYMEX derivative transactions and the right of offset exists. Accordingly, the fair value of all derivative instruments is displayed on a net basis.

Item 4. Controls and Procedures

Disclosure Controls and Procedures

We maintain disclosure controls and procedures that are designed to ensure that the information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act of 1934 (the “Exchange Act”) is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms and that information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure. Under the supervision and with the participation of our principal executive officer and principal financial officer, management evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) or 15d-15(e) of the Exchange Act). Based on that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of September 30, 2011.

Internal Control over Financial Reporting

There has not been any change in our internal control over financial reporting that occurred during the quarter ended September 30, 2011 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

General

Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we do not believe that we are a party to any litigation that will have a material adverse impact on our financial condition or results of operations. Except as described below and in Note 11 in this Quarterly Report on Form 10-Q, we are not aware of any significant legal or governmental proceedings against us, or contemplated to be brought against us. We maintain insurance policies with insurers in amounts and with coverage and deductibles as our general partner believes are reasonable and prudent. However, we can provide no assurance that this insurance will be adequate to protect us from all material expenses related to potential future claims or that these levels of insurance will be available in the future at economically acceptable prices.

Other

In January 2011, the trustee administering the post-bankruptcy litigation trust of Lyondell Chemical Company (“Lyondell”) and certain of its affiliates brought an action against us to recover payments totaling approximately $6.0 million made to us by an affiliate of Lyondell that the trustee claims were paid shortly before the Lyondell bankruptcy and at a time when the affiliate was insolvent, allegedly permitting the avoidance or recovery of those payments pursuant to bankruptcy law. We believe that the payments were made by the affiliate in the ordinary course of both its and our business and as contemporaneous payment for its receipt of a volume of product of a value equivalent to the payments. The litigation is in its early stages, and we believe it has meritorious defenses. Therefore, no provision for losses has been recorded in connection with this matter.

In April 2011, seven operations personnel at our terminal in Chelsea, Massachusetts voted to be represented by the incumbent union representing certain other employees at this facility (“Local 25”). We expect to negotiate a collective bargaining agreement with Local 25 for these employees and do not believe the results of these negotiations will have a material adverse effect on our operations.

Item 1A. Risk Factors

In addition to other information set forth in this report, you should carefully consider the factors discussed in Part I, Item 1A, “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2010, which could materially affect our business, financial condition or future results.

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

Issuer Purchases of Equity Securities

The table below provides information with respect to purchases of our common units made by our general partner on our behalf during the quarter ended September 30, 2011:

				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)
July 1 – July 31, 2011	—	—	—	—
August 1 – August 31, 2011	15,000	18.73	—	194,809
September 1 – September 30, 2011	11,100	20.20	—	183,709

(1) On May 7, 2009, the board of directors of our general partner announced that it authorized the repurchase of our common units for the purpose of meeting our general partner’s anticipated obligations to deliver common units under the LTIP and meeting the general partner’s obligations under existing employment agreements and other employment related obligations of the general partner. Up to 445,000 of our common units in the aggregate is authorized to be acquired, over an extended period of time, consistent with the general partner’s obligations under the LTIP and employment agreements. Common units may be repurchased from time to time in open market transactions, including block purchases, or in privately negotiated transactions.

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

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

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

32.1	†	—	Section 1350 Certification of Chief Executive Officer of Global GP LLC, general partner of Global Partners LP.

32.2	†	—	Section 1350 Certification of Chief Financial Officer of Global GP LLC, general partner of Global Partners LP.

101	*	—	The following financial information from Global Partners LP’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2011, formatted in XBRL includes: (i) Consolidated Statements of Income for the fiscal periods ended September 30, 2011 and 2010, (ii) Consolidated Balance Sheets at September 30, 2011 and December 31, 2010, (iii) Consolidated Statements of Cash Flows for the fiscal periods ended September 30, 2011 and 2010, (iv) Consolidated Statements of Partners’ Equity for the fiscal period ended September 30, 2011 and (v) Notes to Consolidated Financial Statements.

* Filed herewith.

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

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	GLOBAL PARTNERS LP
	By:	Global GP LLC,
		its general partner


Dated: November 4, 2011		By:	/s/ Eric Slifka
			Eric Slifka
			President and Chief Executive Officer
			(Principal Executive Officer)


Dated: November 4, 2011		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		—	Third Amended and Restated Agreement of Limited Partnership of Global Partners LP dated as of December 9, 2009 (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K filed on December 15, 2009).

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

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

32.1	†	—	Section 1350 Certification of Chief Executive Officer of Global GP LLC, general partner of Global Partners LP.

32.2	†	—	Section 1350 Certification of Chief Financial Officer of Global GP LLC, general partner of Global Partners LP.

101	*	—	The following financial information from Global Partners LP’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2011, formatted in XBRL includes: (i) Consolidated Statements of Income for the fiscal periods ended September 30, 2011 and 2010, (ii) Consolidated Balance Sheets at September 30, 2011 and December 31, 2010, (iii) Consolidated Statements of Cash Flows for the fiscal periods ended September 30, 2011 and 2010, (iv) Consolidated Statements of Partners’ Equity for the fiscal period ended September 30, 2011 and (v) Notes to Consolidated Financial Statements.

* Filed herewith.

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