GLOBAL PARTNERS LP - FORM 10-Q

Attached files

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EX-32.2 - EX-32.2 - GLOBAL PARTNERS LP	glp-20170630ex322edb362.htm
EX-32.1 - EX-32.1 - GLOBAL PARTNERS LP	glp-20170630ex3211a1a64.htm
EX-31.2 - EX-31.2 - GLOBAL PARTNERS LP	glp-20170630ex312c30e74.htm
EX-31.1 - EX-31.1 - GLOBAL PARTNERS LP	glp-20170630ex311340bfa.htm

Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2017

OR

☐	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 ☒ No ☐

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 ☒ No ☐

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


Large accelerated filer ☐		Accelerated filer ☒
Non-accelerated filer ☐	(Do not check if a smaller reporting company)	Smaller reporting company ☐
		Emerging growth company ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ◻

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

The issuer had 33,995,563 common units outstanding as of August 7, 2017.

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TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements (unaudited)		3

Consolidated Balance Sheets as of June 30, 2017 and December 31, 2016		3

Consolidated Statements of Operations for the three and six months ended June 30, 2017 and 2016		4

Consolidated Statements of Comprehensive Income (Loss) for the three and six months ended June 30, 2017 and 2016		5

Consolidated Statements of Cash Flows for the six months ended June 30, 2017 and 2016		6

Consolidated Statement of Partners’ Equity for the six months ended June 30, 2017		7

Notes to Consolidated Financial Statements		8

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		49

Item 3. Quantitative and Qualitative Disclosures About Market Risk		75

Item 4. Controls and Procedures		76

PART II. OTHER INFORMATION		78

Item 1. Legal Proceedings		78

Item 1A. Risk Factors		80

Item 6. Exhibits		80

SIGNATURES		81

INDEX TO EXHIBITS		82

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Item 1.Financial Statements

GLOBAL PARTNERS LP

CONSOLIDATED BALANCE SHEETS

(In thousands, except unit data)

(Unaudited)


	June 30,		December 31,
	2017		2016
Assets
Current assets:
Cash and cash equivalents	$	5,922	$	10,028
Accounts receivable, net		260,906		421,360
Accounts receivable—affiliates		3,846		3,143
Inventories		370,364		521,878
Brokerage margin deposits		9,413		27,653
Derivative assets		6,168		21,382
Prepaid expenses and other current assets		74,161		70,022
Total current assets		730,780		1,075,466
Property and equipment, net		1,054,584		1,099,899
Intangible assets, net		59,965		65,013
Goodwill		291,843		294,768
Other assets		60,408		28,874
Total assets	$	2,197,580	$	2,564,020
Liabilities and partners’ equity
Current liabilities:
Accounts payable	$	195,734	$	320,262
Working capital revolving credit facility—current portion		99,100		274,600
Environmental liabilities—current portion		5,334		5,341
Trustee taxes payable		102,330		101,166
Accrued expenses and other current liabilities		54,316		70,443
Derivative liabilities		4,150		27,413
Total current liabilities		460,964		799,225
Working capital revolving credit facility—less current portion		150,000		150,000
Revolving credit facility		200,700		216,700
Senior notes		660,463		659,150
Environmental liabilities—less current portion		53,925		57,724
Financing obligations		152,479		152,444
Deferred tax liabilities		65,338		66,054
Other long-term liabilities		61,046		64,882
Total liabilities		1,804,915		2,166,179
Partners’ equity
Global Partners LP equity:
Common unitholders 33,995,563 units issued and 33,554,328 outstanding at June 30, 2017 and 33,995,563 units issued and 33,543,669 outstanding at December 31, 2016)		395,754		401,044
General partner interest (0.67% interest with 230,303 equivalent units outstanding at June 30, 2017 and December 31, 2016)		(2,990)		(2,948)
Accumulated other comprehensive loss		(4,275)		(5,441)
Total Global Partners LP equity		388,489		392,655
Noncontrolling interest		4,176		5,186
Total partners’ equity		392,665		397,841
Total liabilities and partners’ equity	$	2,197,580	$	2,564,020

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

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GLOBAL PARTNERS LP

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per unit data)

(Unaudited)


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2017		2016		2017		2016
Sales	$	2,089,530	$	2,146,199	$	4,360,314	$	3,897,011
Cost of sales		1,954,168		2,016,857		4,084,925		3,637,610
Gross profit		135,362		129,342		275,389		259,401
Costs and operating expenses:
Selling, general and administrative expenses		34,679		36,640		71,466		71,624
Operating expenses		71,169		75,891		138,382		148,127
Amortization expense		2,260		2,359		4,521		4,868
Net loss (gain) on sale and disposition of assets		2,381		375		(9,481)		6,480
Long-lived asset impairment		—		2,155		—		2,155
Total costs and operating expenses		110,489		117,420		204,888		233,254
Operating income		24,873		11,922		70,501		26,147
Interest expense		(21,923)		(21,015)		(45,210)		(43,995)
Income (loss) before income tax (expense) benefit		2,950		(9,093)		25,291		(17,848)
Income tax (expense) benefit		(959)		550		(795)		1,470
Net income (loss)		1,991		(8,543)		24,496		(16,378)
Net loss attributable to noncontrolling interest		383		1,233		824		2,044
Net income (loss) attributable to Global Partners LP		2,374		(7,310)		25,320		(14,334)
Less: General partner’s interest in net income (loss), including incentive distribution rights		16		(49)		170		(96)
Limited partners’ interest in net income (loss)	$	2,358	$	(7,261)	$	25,150	$	(14,238)
Basic net income (loss) per limited partner unit	$	0.07	$	(0.22)	$	0.75	$	(0.42)
Diluted net income (loss) per limited partner unit	$	0.07	$	(0.22)	$	0.75	$	(0.42)
Basic weighted average limited partner units outstanding		33,554		33,518		33,554		33,518
Diluted weighted average limited partner units outstanding		33,652		33,518		33,619		33,518

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

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GLOBAL PARTNERS LP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(In thousands)

(Unaudited)


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2017		2016		2017		2016
Net income (loss)	$	1,991	$	(8,543)	$	24,496	$	(16,378)
Other comprehensive income:
Change in fair value of cash flow hedges		199		592		597		853
Change in pension liability		250		306		569		374
Total other comprehensive income		449		898		1,166		1,227
Comprehensive income (loss)		2,440		(7,645)		25,662		(15,151)
Comprehensive loss attributable to noncontrolling interest		383		1,233		824		2,044
Comprehensive income (loss) attributable to Global Partners LP	$	2,823	$	(6,412)	$	26,486	$	(13,107)

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

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GLOBAL PARTNERS LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)


	Six Months Ended
	June 30,
	2017		2016
Cash flows from operating activities
Net income (loss)	$	24,496	$	(16,378)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation and amortization		52,913		57,949
Amortization of deferred financing fees		2,955		2,948
Amortization of leasehold interests		528		626
Amortization of senior notes discount		716		690
Bad debt expense		855		50
Unit-based compensation expense		625		2,150
Write-off of financing fees		573		1,828
Net (gain) loss on sale and disposition of assets		(9,481)		6,480
Long-lived asset impairment		—		2,155
Changes in operating assets and liabilities, excluding net assets acquired:
Accounts receivable		159,599		(46,838)
Accounts receivable-affiliate		(703)		(1,284)
Inventories		150,762		(55,042)
Broker margin deposits		18,240		(8,036)
Prepaid expenses, all other current assets and other assets		(37,861)		(2,277)
Accounts payable		(124,527)		(16,974)
Trustee taxes payable		1,164		1,100
Change in derivatives		(9,540)		28,686
Accrued expenses, all other current liabilities and other long-term liabilities		(21,387)		(17,816)
Net cash provided by (used in) operating activities		209,927		(59,983)
Cash flows from investing activities
Capital expenditures		(19,308)		(38,846)
Proceeds from sale of property and equipment		28,238		11,682
Net cash provided by (used in) investing activities		8,930		(27,164)
Cash flows from financing activities
Net (payments on) borrowings from working capital revolving credit facility		(175,500)		120,700
Net payments on revolving credit facility		(16,000)		(55,600)
Proceeds from sale-leaseback, net		—		62,476
Noncontrolling interest capital contribution		279		—
Distribution to noncontrolling interest		(465)		(1,798)
Distributions to partners		(31,277)		(31,153)
Net cash (used in) provided by financing activities		(222,963)		94,625
Cash and cash equivalents
(Decrease) increase in cash and cash equivalents		(4,106)		7,478
Cash and cash equivalents at beginning of period		10,028		1,116
Cash and cash equivalents at end of period	$	5,922	$	8,594
Supplemental information
Cash paid during the period for interest	$	22,612	$	23,016

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

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GLOBAL PARTNERS LP

CONSOLIDATED STATEMENTS OF PARTNERS’ EQUITY

(In thousands)

(Unaudited)


					Accumulated
			General		Other				Total
	Common		Partner		Comprehensive		Noncontrolling		Partners’
	Unitholders		Interest		Loss		Interest		Equity
Balance at December 31, 2016	$	401,044	$	(2,948)	$	(5,441)	$	5,186	$	397,841
Net income (loss)		25,150		170		—		(824)		24,496
Noncontrolling interest capital contribution		—		—		—		279		279
Distribution to noncontrolling interest		—		—		—		(465)		(465)
Other comprehensive income		—		—		1,166		—		1,166
Unit-based compensation		625		—		—		—		625
Distributions to partners		(31,446)		(212)		—		—		(31,658)
Dividends on repurchased units		381		—		—		—		381
Balance at June 30, 2017	$	395,754	$	(2,990)	$	(4,275)	$	4,176	$	392,665

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

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1. Organization and Basis of Presentation

Organization

Global Partners LP (the “Partnership”) is a midstream logistics and marketing master limited partnership formed in March 2005 engaged in the purchasing, selling, storing and logistics of transporting petroleum and related products, including gasoline and gasoline blendstocks (such as ethanol), distillates (such as home heating oil, diesel and kerosene), residual oil, renewable fuels, crude oil and propane. The Partnership owns, controls or has access to one of the largest terminal networks of refined petroleum products and renewable fuels in Massachusetts, Maine, Connecticut, Vermont, New Hampshire, Rhode Island, New York, New Jersey and Pennsylvania (collectively, the “Northeast”). The Partnership is one of the largest distributors of gasoline, distillates, residual oil and renewable fuels to wholesalers, retailers and commercial customers in the New England states and New York. The Partnership is also one of the largest independent owners, suppliers and operators of gasoline stations and convenience stores with locations throughout the New England states and New York. As of June 30, 2017, the Partnership had a portfolio of 1,443 owned, leased and/or supplied gasoline stations, including 239 directly operated convenience stores, in the Northeast, Maryland and Virginia. The Partnership also receives revenue from convenience store sales, rental income and sundries.

In addition, the Partnership owns transload and storage terminals in North Dakota and Oregon that extend its origin-to-destination capabilities from the mid-continent region of the United States and Canada.

Global GP LLC, the Partnership’s general partner (the “General Partner”), manages the Partnership’s operations and activities and employs its officers and substantially all of its personnel, except for most of its gasoline station and convenience store employees who are employed by Global Montello Group Corp. (“GMG”), a wholly owned subsidiary of the Partnership.

The General Partner, which holds a 0.67% general partner interest in the Partnership, is owned by affiliates of the Slifka family. As of June 30, 2017, affiliates of the General Partner, including its directors and executive officers and their affiliates, owned 7,433,829 common units, representing a 21.9% limited partner interest.

Recent Transactions

Amended and Restated Credit Agreement— On April 25, 2017, the Partnership and certain of its subsidiaries entered into a third amended and restated credit agreement with aggregate commitments of $1.3 billion and a maturity date of April 30, 2020. See Note 7 for additional information.

Sale of Natural Gas and Electricity Brokerage Businesses—On February 1, 2017, the Partnership completed the sale of its natural gas marketing and electricity brokerage businesses for a purchase price of approximately $17.3 million, subject to customary closing adjustments. Proceeds from the sale amounted to approximately $16.3 million, and the Partnership realized a gain on the sale of $14.2 million. The sale of the natural gas marketing and electricity brokerage businesses reflects the Partnership’s ongoing program to monetize non-strategic assets not fundamental to its growth strategy. Prior to the sale, the results of natural gas marketing and electricity brokerage businesses were included in the Commercial segment. See Note 6.

Basis of Presentation

The accompanying consolidated financial statements as of June 30, 2017 and December 31, 2016 and for the three and six months ended June 30, 2017 and 2016 reflect the accounts of the Partnership. Upon consolidation, all intercompany balances and transactions have been eliminated.

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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, 2016 and notes thereto contained in the Partnership’s Annual Report on Form 10-K. The significant accounting policies described in Note 2, “Summary of Significant Accounting Policies,” of such Annual Report on Form 10-K are the same used in preparing the accompanying consolidated financial statements.

The results of operations for the three and six months ended June 30, 2017 are not necessarily indicative of the results of operations that will be realized for the entire year ending December 31, 2017. The consolidated balance sheet at December 31, 2016 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, 2016.

Noncontrolling Interest

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

Concentration of Risk

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

The following table presents the Partnership’s product sales and other revenues as a percentage of the consolidated sales for the periods presented:


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2017		2016		2017		2016
Gasoline sales: gasoline and gasoline blendstocks (such as ethanol)	67	%	68	%	62	%	63	%
Crude oil sales and crude oil logistics revenue	7	%	7	%	6	%	8	%
Distillates (home heating oil, diesel and kerosene), residual oil, natural gas and propane sales	22	%	20	%	28	%	25	%
Convenience store sales, rental income and sundries	4	%	5	%	4	%	4	%
Total	100	%	100	%	100	%	100	%

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The following table presents the Partnership’s product margin by segment as a percentage of the consolidated product margin for the periods presented:


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2017		2016		2017		2016
Wholesale segment	20	%	21	%	26	%	23	%
Gasoline Distribution and Station Operations segment	77	%	75	%	71	%	73	%
Commercial segment	3	%	4	%	3	%	4	%
Total	100	%	100	%	100	%	100	%

See Note 15, “Segment Reporting,” for additional information on the Partnership’s operating segments.

None of the Partnership’s customers accounted for greater than 10% of total sales for the three and six months ended June 30, 2017 and 2016.

Note 2. Net Income (Loss) 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 or losses is assumed to be allocated to the common unitholders, or limited partners’ interest, and to the General Partner’s general partner interest.

Common units outstanding as reported in the accompanying consolidated financial statements at June 30, 2017 and December 31, 2016 excluded 441,235 and 451,894 common units, respectively, held on behalf of the Partnership pursuant to its repurchase program (see Note 12). These units are not deemed outstanding for purposes of calculating net income (loss) per limited partner unit (basic and diluted).

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The following table provides a reconciliation of net income (loss) and the assumed allocation of net income (loss) to the limited partners’ interest for purposes of computing net income (loss) per limited partner unit for the periods presented (in thousands, except per unit data):


	Three Months Ended June 30, 2017								Three Months Ended June 30, 2016
			Limited		General						Limited		General
			Partner		Partner						Partner		Partner
Numerator:	Total		Interest		Interest		IDRs		Total		Interest		Interest		IDRs
Net income (loss) attributable to Global Partners LP	$	2,374	$	2,358	$	16	$	—	$	(7,310)	$	(7,261)	$	(49)	$	—
Declared distribution	$	15,829	$	15,723	$	106	$	—	$	15,829	$	15,723	$	106	$	—
Assumed allocation of undistributed net income (loss)		(13,455)		(13,365)		(90)		—		(23,139)		(22,984)		(155)		—
Assumed allocation of net income (loss)	$	2,374	$	2,358	$	16	$	—	$	(7,310)	$	(7,261)	$	(49)	$	—

Denominator:
Basic weighted average limited partner units outstanding				33,554								33,518
Dilutive effect of phantom units				98								—
Diluted weighted average limited partner units outstanding				33,652								33,518
Basic net income (loss) per limited partner unit			$	0.07							$	(0.22)
Diluted net income (loss) per limited partner unit (1)			$	0.07							$	(0.22)

(1)

Basic limited partner units were used to calculate diluted net loss per limited partner unit for the three months ended June 30, 2016, as using the effects of phantom units would have an anti-dilutive effect on net loss per limited partner unit.

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)


	Six Months Ended June 30, 2017								Six Months Ended June 30, 2016
			Limited		General						Limited		General
			Partner		Partner						Partner		Partner
Numerator:	Total		Interest		Interest		IDRs		Total		Interest		Interest		IDRs
Net income (loss) attributable to Global Partners LP	$	25,320	$	25,150	$	170	$	—	$	(14,334)	$	(14,238)	$	(96)	$	—
Declared distribution	$	31,658	$	31,446	$	212	$	—	$	31,658	$	31,446	$	212	$	—
Assumed allocation of undistributed net income (loss)		(6,338)		(6,296)		(42)		—		(45,992)		(45,684)		(308)		—
Assumed allocation of net income (loss)	$	25,320	$	25,150	$	170	$	—	$	(14,334)	$	(14,238)	$	(96)	$	—

Denominator:
Basic weighted average limited partner units outstanding				33,554								33,518
Dilutive effect of phantom units				65								—
Diluted weighted average limited partner units outstanding				33,619								33,518
Basic net income (loss) per limited partner unit			$	0.75							$	(0.42)
Diluted net income (loss) per limited partner unit (1)			$	0.75							$	(0.42)

(1)

Basic limited partner units were used to calculate diluted net loss per limited partner unit for the six months ended June 30, 2016, as using the effects of phantom units would have an anti-dilutive effect on net loss per limited partner unit.

The board of directors of the General Partner declared the following quarterly cash distributions:


	Per Unit Cash		Distribution Declared for the
Cash Distribution Declaration Date	Distribution Declared		Quarterly Period Ended
April 28, 2017	$	0.4625	March 31, 2017
July 28, 2017	$	0.4625	June 30, 2017

See Note 13, “Partners’ Equity and Cash Distributions” for further information.

Note 3. Inventories

The Partnership hedges substantially all of its petroleum and ethanol inventory using a variety of instruments, primarily exchange-traded futures contracts. These futures contracts are entered into when inventory is purchased and are either designated as fair value hedges against the inventory on a specific barrel basis for inventories qualifying for fair value hedge accounting or not designated and maintained as economic hedges against certain inventory of the Partnership on a specific barrel basis. Changes in fair value of these futures contracts, as well as the offsetting change in fair value on the hedged inventory, are recognized in earnings as an increase or decrease in cost of sales. All hedged inventory designated in a fair value hedge relationship is valued using the lower of cost, as determined by specific identification, or net realizable value, as determined at the product level. All petroleum and ethanol inventory not designated in a fair value hedging relationship is carried at the lower of historical cost, on a first-in, first-out basis, or net realizable value.

Convenience store inventory and Renewable Identification Numbers (“RINs”) inventory are carried at the lower of historical cost or net realizable value.

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Inventories consisted of the following (in thousands):


	June 30,		December 31,
	2017		2016
Distillates: home heating oil, diesel and kerosene	$	145,630	$	180,272
Gasoline		74,918		101,368
Gasoline blendstocks		57,564		54,582
Crude oil		57,018		136,113
Residual oil		17,594		29,536
Propane and other		562		3,167
Renewable identification numbers (RINs)		595		631
Convenience store inventory		16,483		16,209
Total	$	370,364	$	521,878

In addition to its own inventory, the Partnership has exchange agreements for petroleum products and ethanol 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 $6.2 million and $4.0 million at June 30, 2017 and December 31, 2016, respectively. Negative exchange balances are accounted for as accounts payable and amounted to $14.6 million and $13.4 million at June 30, 2017 and December 31, 2016, respectively. Exchange transactions are valued using current carrying costs.

Note 4. Goodwill

The following table presents changes in goodwill, all of which has been allocated to the Gasoline Distribution and Station Operations (“GDSO”) segment (in thousands):


Balance at December 31, 2016	$	294,768
Disposals (1)		(2,925)
Balance at June 30, 2017	$	291,843

(1)

Disposals represent derecognition of goodwill associated with the sale and disposition of certain assets. See Note 6.

Note 5. Property and Equipment

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


	June 30,		December 31,
	2017		2016
Buildings and improvements	$	1,000,922	$	984,373
Land		409,471		418,025
Fixtures and equipment		41,450		40,354
Idle plant assets		30,500		30,500
Construction in process		30,455		42,069
Capitalized internal use software		20,660		20,097
Total property and equipment		1,533,458		1,535,418
Less accumulated depreciation		478,874		435,519
Total	$	1,054,584	$	1,099,899

Property and equipment includes assets held for sale of $7.9 million and $17.5 million at June 30, 2017 and December 31, 2016, respectively.

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At June 30, 2017, the Partnership had a $60.0 million remaining net book value of long-lived assets at its West Coast facility, including $30.5 million related to the Partnership’s ethanol plant acquired in 2013. In 2016, the Partnership shifted the facility from crude oil to ethanol transloading and began transloading ethanol. The Partnership would need to take certain measures to prepare the facility for ethanol production in order to place the plant into service. Therefore, the $30.5 million related to the ethanol plant was included in property and equipment and classified as idle plant assets at June 30, 2017 and December 31, 2016.

If the Partnership is unable to generate cash flows to support the recoverability of the plant and facility assets, this may become an indicator of potential impairment of the West Coast facility. Associated with the fair value appraisals determined by third-party valuation specialists in support of the Partnership’s 2016 step two goodwill impairment test, the Partnership received an estimated fair value for the West Coast facility significantly in excess of the $60.0 million remaining net book value. The estimated fair value obtained was based on market comparable transactions for sale of ethanol plant assets, both active and idle, at the time of sale. While the fair value analysis was not prepared or obtained to support the recoverability of the West Coast facility or idle plant assets, the Partnership does not believe that changes in assumptions would impact the estimated fair value such that it might result in a fair value estimate of the West Coast facility that would be less than the $60.0 million net book value at June 30, 2017. The Partnership will continue to monitor the market for ethanol, the continued business development of this facility for either ethanol or crude oil transloading, and the related impact this may have on the facility’s operating cash flows and whether this would constitute an impairment indicator.

For the three and six months ended June 30, 2017, the Partnership did not record any long-lived asset impairment charges. For the three and six months ended June 30, 2016, the Partnership recognized an impairment charge of $1.9 million associated with the long-lived assets used in supplying compressed natural gas (“CNG”) which is viewed as an alternative fuel to oil. The CNG assets were allocated to the Commercial segment. On November 1, 2016, the Partnership sold its CNG assets. In addition, the Partnership recognized an impairment charge of $0.3 million for the three and six months ended June 30, 2016 associated with the long-lived assets of one discrete GDSO site in its GDSO reporting unit.

Note 6. Sales and Disposition of Assets

The following table provides the Partnership’s (gain) loss on sale and dispositions of assets for the periods presented (in thousands):


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2017		2016		2017		2016
Sale of natural gas brokerage and electricity businesses	$	—	$	—	$	(14,172)	$	—
Periodic divestiture of gasoline stations		357		78		176		657
Strategic asset divestiture program		27		—		450		—
Loss on assets held for sale		1,388		108		3,439		5,644
Other		609		189		626		179
Net loss (gain) on sale and disposition of assets	$	2,381	$	375	$	(9,481)	$	6,480

Sale of Natural Gas and Electricity Brokerage Businesses

On February 1, 2017, the Partnership completed the sale of its natural gas marketing and electricity brokerage businesses for a purchase price of approximately $17.3 million, subject to customary closing adjustments. Proceeds from the sale amounted to approximately $16.3 million, and the Partnership realized a gain on the sale of $14.2 million for the six months ended June 30, 2017. See Note 1.

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Periodic Divestiture of Gasoline Stations

As part of the routine course of operations in the GDSO segment, the Partnership may periodically divest certain gasoline stations. The gain or loss on the sale, representing cash proceeds less net book value of assets and recognized liabilities at disposition, net of settlement and dispositions costs, is recorded in net loss (gain) on sale and disposition of assets in the accompanying consolidated statements of operations and amounted to losses of $0.4 million and $0.1 million for the three months ended June 30, 2017 and 2016 respectively, and $0.2 million and $0.7 million for the six months ended June 30, 2017 and 2016, respectively.

Strategic Asset Divestiture Program

The Partnership identified certain non-strategic GDSO sites that are part of its Strategic Asset Divestiture Program (the “Divestiture Program”).

The Partnership has retained a real estate firm to coordinate the sale of approximately 75 non-strategic GDSO sites. As of June 30, 2017 and since the Divesture Program was implemented, the Partnership has completed the sale of 53 of these sites, of which 8 sites and 24 sites were sold during the three and six months ended June 30, 2017, respectively. The gain or loss on the sale, representing cash proceeds less net book value of assets and recognized liabilities at disposition, net of settlement and dispositions costs, is recorded in net loss (gain) on sale and disposition of assets in the accompanying consolidated statements of operations and amounted to losses of $27,000 and $0.5 million for the three and six months ended June 30, 2017, respectively, including the derecognition of GDSO goodwill in the amount of $0.9 million and $2.9 million for the three and six months ended June 30, 2017, respectively. As of June 30, 2017, the criteria to be presented as held for sale was met for 14 of the remaining sites.

Loss on Assets Held for Sale

In conjunction with the periodic divestiture of gasoline stations and the sale of sites within the Divestiture Program, the Partnership may classify certain gasoline station assets as held for sale.

The Partnership classified 11 sites and 17 sites as held for sale at June 30, 2017 and December 31, 2016, respectively, which are periodic divestiture gasoline station sites. The Partnership recorded impairment charges related to these assets held for sale in the amount of $0.2 million and $0.1 million for the three months ended June 30, 2017 and 2016, respectively, and $0.4 million and $5.6 million for the six months ended June 30, 2017 and 2016, respectively, which are included in net loss (gain) on sale and disposition of assets in the accompanying consolidated statements of operations.

Additionally, the Partnership classified 14 sites associated with the real estate firm coordinated sale discussed above as held for sale at June 30, 2017. The Partnership recorded impairment charges related to these assets held for sale in the amount of $1.2 million and $3.1 million for the three and six months ended June 30, 2017, respectively, which are included in net loss (gain) on sale and disposition of assets in the accompanying consolidated statements of operations. No impairment charges were required related to the Partnership’s assets classified as held for sale for the three and six months ended June 30, 2016.

Assets held for sale of $7.9 million and $17.5 million at June 30, 2017 and December 31, 2016, respectively, are included in property and equipment in the accompanying balance sheets. Assets held for sale are expected to be sold within the next 12 months.

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Other

The Partnership recognizes gains and losses on the sale and disposition of other assets, including vehicles, fixtures and equipment, and the gain or loss on such other assets are included in other in the aforementioned table.

Note 7. Debt and Financing Obligations

Credit Agreement

On April 25, 2017, the Partnership, its operating company, its operating subsidiaries and GLP Finance Corp., as borrowers, entered into a Third Amended and Restated Credit Agreement (the “Credit Agreement”), with Aggregate Commitments (as defined in the Credit Agreement) available in the amount of $1.3 billion. The Credit Agreement matures on April 30, 2020.

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 $850.0 million; and

a $450.0 million revolving credit facility to be used for acquisitions, joint ventures, capital expenditures, letters of credit and general corporate purposes.

In addition, the Credit Agreement has an accordion feature whereby the Partnership may request on the same terms and conditions then applicable to the Credit Agreement, provided no Event of Default (as defined in the Credit Agreement) then exists, an increase to the working capital revolving credit facility, the revolving credit facility, or both, by up to another $300.0 million, in the aggregate, for a total credit facility of up to $1.6 billion. Any such request for an increase must be in a minimum amount of $25.0 million. The Partnership cannot provide assurance, however, that its lending group will agree to fund any request by the Partnership for additional amounts in excess of the total available commitments of $1.3 billion.

In addition, the Credit Agreement includes a swing line pursuant to which Bank of America, N.A., as the swing line lender, may make swing line loans in U.S. dollars in an aggregate amount equal to the lesser of (a) $75.0 million and (b) the Aggregate WC Commitments (as defined in the Credit Agreement). Swing line loans will bear interest at the Base Rate (as defined in the Credit Agreement). The swing line is a sub-portion of the working capital revolving credit facility and is not an addition to the total available commitments of $1.3 billion.

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

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

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depending on the Utilization Amount (as defined in the Credit Agreement). Borrowings under the revolving credit facility bear interest at (1) the Eurocurrency rate plus 2.00% to 3.00%, (2) the cost of funds rate plus 2.00% to 3.00%, or (3) the base rate plus 1.00% to 2.00%, each depending on the Combined Total Leverage Ratio (as defined in the Credit Agreement).

The average interest rates for the Credit Agreement were 3.6% and 3.5% for the three months ended June 30, 2017 and 2016, respectively, and 3.5% and 3.7% for the six months ended June 30, 2017 and 2016, respectively. The decline in the average interest rates for the six months ended June 30, 2017 is due to the May 2016 expiration of an interest rate swap.

The Credit Agreement provides for a letter of credit fee equal to the then applicable working capital rate or then applicable revolver rate (each such rate as defined in the Credit Agreement) per annum for each letter of credit issued. In addition, the Partnership incurs a commitment fee on the unused portion of each facility under the Credit Agreement, ranging from 0.35% to 0.50% per annum.

The Partnership classifies a portion of its working capital revolving credit facility as a current liability and a portion as a long-term liability. The portion classified as a long-term liability represents the amounts expected to be outstanding during the entire year based on an analysis of historical daily borrowings under the working capital revolving credit facility, the seasonality of borrowings, forecasted future working capital requirements and forward product curves, and because the Partnership has a multi-year, long-term commitment from its bank group. Accordingly, at June 30, 2017, the Partnership estimated working capital revolving credit facility borrowings will equal or exceed $150.0 million over the next twelve months and, therefore, classified $99.1 million as the current portion at June 30, 2017, representing the amount the Partnership expects to pay down over the next twelve months. The long-term portion of the working capital revolving credit facility was $150.0 million at each of June 30, 2017 and December 31, 2016, and the current portion was $99.1 million and $274.6 million at June 30, 2017 and December 31, 2016, respectively. The decrease in total borrowings under the working capital revolving credit facility of $175.5 million from December 31, 2016 was primarily due to decreases in accounts receivable and inventories, in part due to seasonality relating to the heating season, reduced inventory volume and a decline in prices.

As of June 30, 2017, the Partnership had total borrowings outstanding under the Credit Agreement of $449.8 million, including $200.7 million outstanding on the revolving credit facility. In addition, the Partnership had outstanding letters of credit of $30.2 million. Subject to borrowing base limitations, the total remaining availability for borrowings and letters of credit was $820.0 million and $764.8 million at June 30, 2017 and December 31, 2016, respectively.

The Credit Agreement is secured by substantially all of the assets of the Partnership and the Partnership’s wholly-owned subsidiaries and is guaranteed by the Partnership and its subsidiaries, Bursaw Oil LLC, Global Partners Energy Canada ULC, Warex Terminals Corporation, Drake Petroleum Company, Inc., Puritan Oil Company, Inc. and Maryland Oil Company, Inc.

The Credit Agreement imposes certain requirements on the borrowers including, for example, a prohibition against distributions if any potential default or Event of Default (as defined in the Credit Agreement) would occur as a result thereof, and certain limitations on the Partnership’s ability to grant liens, make certain loans or investments, incur additional indebtedness or guarantee other indebtedness, make any material change to the nature of the Partnership’s business or undergo a fundamental change, make any material dispositions, acquire another company, enter into a merger, consolidation, sale leaseback transaction or purchase of assets, or make capital expenditures in excess of specified levels.

The Credit Agreement also includes certain baskets that were not included in the prior credit agreement, including: (i) a $25.0 million general secured indebtedness basket, (ii) a $25.0 million general investment basket, (iii) a

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$75.0 million secured indebtedness basket to permit the borrowers to enter into a Contango Facility (as defined in the Credit Agreement), (iv) a Sale/Leaseback Transaction (as defined in the Credit Agreement) basket of $100.0 million, and (v) a basket of $50.0 million in an aggregate amount over the life of the Credit Agreement for the purchase of common units of the Partnership, provided that no Event of Default exists or would occur immediately following such purchase(s).

In addition, the Credit Agreement provides the ability for the borrowers to repay certain junior indebtedness, subject to a $100.0 million cap, so long as no Event of Default has occurred or will exist immediately after making such repayment.

The Credit Agreement imposes financial covenants that require the Partnership to maintain certain minimum working capital amounts, a minimum combined interest coverage ratio, a maximum senior secured leverage ratio and a maximum total leverage ratio. The Partnership was in compliance with the foregoing covenants at June 30, 2017. The Credit Agreement also contains a representation whereby there can be no event or circumstance, either individually or in the aggregate, that has had or could reasonably be expected to have a Material Adverse Effect (as defined in the Credit Agreement). In addition, the Credit Agreement limits distributions by the Partnership to its unitholders to the amount of Available Cash (as defined in the Partnership’s partnership agreement).

Senior Notes

The Partnership had 6.25% senior notes due 2022 and 7.00% senior notes due 2023 outstanding at June 30, 2017. Please read Note 6 of Notes to Consolidated Financial Statements in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2016 for additional information on these senior notes.

Financing Obligations

Capitol Acquisition

On June 1, 2015, the Partnership acquired retail gasoline stations and dealer supply contracts from Capitol Petroleum Group (“Capitol”). In connection with the acquisition, the Partnership assumed a financing obligation of $89.6 million associated with two sale-leaseback transactions by Capitol for 53 leased sites that did not meet the criteria for sale accounting. During the terms of these leases, which expire in May 2028 and September 2029, in lieu of recognizing lease expense for the lease rental payments, the Partnership incurs interest expense associated with the financing obligation. Interest expense of approximately $2.4 million was recorded for each of the three months ended June 30, 2017 and 2016, and $4.8 million was recorded for each of the six months ended June 30, 2017 and 2016 and is included in interest expense in the accompanying statements of operations. The financing obligation will amortize through expiration of the leases based upon the lease rental payments which were $2.4 million for each of the three months ended June 30, 2017 and 2016, and $4.8 million and $4.7 million for the six months ended June 30, 2017 and 2016, respectively. The financing obligation balance outstanding at June 30, 2017 was $89.9 million associated with the Capitol acquisition.

Sale Leaseback Transaction

On June 29, 2016, the Partnership sold to a premier institutional real estate investor (the “Buyer”) real property assets, including the buildings, improvements and appurtenances thereto, at 30 gasoline stations and convenience stores located in Connecticut, Maine, Massachusetts, New Hampshire and Rhode Island (the “Sale Leaseback Sites”) for a purchase price of approximately $63.5 million. In connection with the sale, the Partnership entered into a Master Unitary Lease Agreement with the Buyer to lease back the real property assets sold with respect to the Sale Leaseback Sites (such Master Lease Agreement, together with the Sale Leaseback Sites, the “Sale Leaseback Transaction”). The Master Unitary Lease Agreement provides for an initial term of fifteen years that expires in 2031. The Partnership has one successive option to renew the

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lease for a ten-year period followed by two successive options to renew the lease for five-year periods on the same terms, covenants, conditions and rental as the primary non-revocable lease term. The Partnership does not have any residual interest nor the option to repurchase any of the sites at the end of the lease term. The proceeds from the Sale Leaseback Transaction were used to reduce indebtedness outstanding under the Partnership’s revolving credit facility.

The sale did not meet the criteria for sale accounting as of June 30, 2017 due to prohibited continuing involvement. Specifically, the sale is considered a partial-sale transaction, which is a form of continuing involvement as the Partnership did not transfer to the Buyer the storage tank systems which are considered integral equipment of the Sale Leaseback Sites. Additionally, a portion of the sold sites have material sub-lease arrangements, which is also a form of continuing involvement. As the sale of the Sale-Leaseback Sites did not meet the criteria for sale accounting, the Partnership did not recognize a gain or loss on the sale of the Sale Leaseback Sites for the three and six months ended June 30, 2017.

As a result of not meeting the criteria for sale accounting for these sites, the Sale Leaseback Transaction is accounted for as a financing arrangement. As such, the property and equipment sold and leased back by the Partnership has not been derecognized and continues to be depreciated. The Partnership recognized a corresponding financing obligation of $62.5 million equal to the $63.5 million cash proceeds received for the sale of these sites, net of $1.0 million financing fees. During the term of the lease, which expires in June 2031, in lieu of recognizing lease expense for the lease rental payments, the Partnership incurs interest expense associated with the financing obligation. Lease rental payments are recognized as both interest expense and a reduction of the principal balance associated with the financing obligation. Interest expense and lease rental payments were $1.1 million and $2.2 million for the three and six months ended June 30, 2017, respectively. Interest expense and lease rental payments were immaterial for the three and six months ended June 30, 2016. The financing obligation balance outstanding at June 30, 2017 was $62.5 million associated with the Sale Leaseback Transaction.

Deferred Financing Fees

The Partnership incurs bank fees related to its Credit Agreement and other financing arrangements. These deferred financing fees are capitalized and amortized over the life of the Credit Agreement or other financing arrangements. In connection with the amendment to the Credit Agreement in April 2017, the Partnership capitalized additional financing fees of $8.0 million for the six months ended June 30, 2017. The Partnership had unamortized deferred financing fees of $18.6 million and $14.1 million at June 30, 2017 and December 31, 2016, respectively.

Unamortized fees related to the Credit Agreement are included in other current assets and other long-term assets and amounted to $11.7 million and $6.5 million at June 30, 2017 and December 31, 2016, respectively. Unamortized fees related to the senior notes are presented as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts, and amounted to $6.0 million and $6.6 million at June 30, 2017 and December 31, 2016, respectively. Unamortized fees related to the Sale-Leaseback Transaction are presented as a direct deduction from the carrying amount of the financing obligation and amounted to $0.9 million and $1.0 million at June 30, 2017 and December 31, 2016, respectively.

On April 25, 2017, the Partnership entered into the Credit Agreement, a new facility that extended the maturity date and reduced the total commitment of the prior credit agreement. As a result, the Partnership incurred expenses of approximately $0.6 million associated with the write-off of a portion of the related deferred financing fees. These expenses are included in interest expense in the accompanying statements of operations for each of the three and six months ended June 30, 2017.

On February 24, 2016, under its prior credit agreement, the Partnership voluntarily elected to reduce its working capital revolving credit facility from $1.0 billion to $900.0 million and its revolving credit facility from $775.0 million to $575.0 million. As a result, the Partnership incurred expenses of approximately $1.8 million associated with the write-

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off of a portion the related deferred financing fees. These expenses are included in interest expense in the accompanying statement of operations for the six months ended June 30, 2016.

Amortization expense of approximately $1.4 million and $1.5 million for the three months ended June 30, 2017 and 2016, respectively, and $2.9 million for each of the six months ended June 30, 2017 and 2016 is included in interest expense in the accompanying consolidated statements of operations.

Note 8. Derivative Financial Instruments

The Partnership principally uses derivative instruments, which include regulated exchange-traded futures and options contracts (collectively, “exchange-traded derivatives”) and physical and financial forwards and over-the-counter (“OTC”) swaps (collectively, “OTC derivatives”), to reduce its exposure to unfavorable changes in commodity market prices and interest rates. The Partnership uses these exchange-traded and OTC derivatives to hedge commodity price risk associated with its inventory and undelivered forward commodity purchases and sales (“physical forward contracts”) and uses interest rate swap instruments to reduce its exposure to fluctuations in interest rates associated with the Partnership’s credit facilities. The Partnership accounts for derivative transactions in accordance with ASC Topic 815, “Derivatives and Hedging,” and recognizes derivatives instruments as either assets or liabilities in the consolidated balance sheet and measures those instruments at fair value. The changes in fair value of the derivative transactions are presented currently in earnings, unless specific hedge accounting criteria are met.

The fair value of exchange-traded derivative transactions reflects amounts that would be received from or paid to the Partnership’s brokers upon liquidation of these contracts. The fair value of these exchange-traded derivative transactions are presented on a net basis, offset by the cash balances on deposit with the Partnership’s brokers, presented as brokerage margin deposits in the consolidated balance sheets. The fair value of OTC derivative transactions reflects amounts that would be received from or paid to a third party upon liquidation of these contracts under current market conditions. The fair value of these OTC derivative transactions is presented on a gross basis as derivative assets or derivative liabilities in the consolidated balance sheets, unless a legal right of offset exists. The presentation of the change in fair value of the Partnership’s exchange-traded derivatives and OTC derivative transactions depends on the intended use of the derivative and the resulting designation.

The following table summarizes the notional values related to the Partnership’s derivative instruments outstanding at June 30, 2017:


	Units (1)		Unit of Measure
Exchange-Traded Derivatives
Long		118,624	Thousands of barrels
Short		(122,102)	Thousands of barrels

OTC Derivatives (Petroleum/Ethanol)
Long		7,012	Thousands of barrels
Short		(4,642)	Thousands of barrels

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

(1)

Number of open positions and gross notional values do not measure the Partnership’s risk of loss, quantify risk or represent assets or liabilities of the Partnership, but rather indicate the relative size of the derivative instruments and are used in the calculation of the amounts to be exchanged between counterparties upon settlements.

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Derivatives Accounted for as Hedges

The Partnership utilizes fair value hedges and cash flow hedges to hedge commodity price risk and interest rate risk.

Fair Value Hedges

Derivatives designated as fair value hedges are used to hedge price risk in commodity inventories and principally include exchange-traded futures contracts that are entered into in the ordinary course of business. For a derivative instrument designated as a fair value hedge, the gain or loss is recognized in earnings in the period of change together with the offsetting change in fair value on the hedged item of the risk being hedged. Gains and losses related to fair value hedges are recognized in the consolidated statement of operations through cost of sales. These futures contracts are settled on a daily basis by the Partnership through brokerage margin accounts.

The Partnership’s fair value hedges include exchange-traded futures contracts and OTC derivative contracts that are hedges against inventory with specific futures contracts matched to specific barrels. The change in fair value of these futures contracts and the change in fair value of the underlying inventory generally provide an offset to each other in the consolidated statement of operations.

The following table presents the gains and losses from the Partnership’s derivative instruments involved in fair value hedging relationships recognized in the consolidated statements of operations for the periods presented (in thousands):


	Statement of Gain (Loss)	Three Months Ended				Six Months Ended
	Recognized in Income on	June 30,				June 30,
	Derivatives	2017		2016		2017		2016
Derivatives in fair value hedging relationship
Exchange-traded futures contracts and OTC derivative contracts for petroleum commodity products	Cost of sales	$	20,224	$	(45,891)	$	40,920	$	(18,052)

Hedged items in fair value hedge relationship
Physical inventory	Cost of sales	$	(20,937)	$	52,663	$	(41,782)	$	28,488

Cash Flow Hedges

At June 30 2017, the Partnership had in place one interest rate swap agreement which is hedging $100.0 million of variable rate debt and continues to be accounted for as a cash flow hedge.

The amount of gain (loss) recognized in other comprehensive income as effective for derivatives designated in cash flow hedging relationships was $199,000 and $511,000 for the three months ended June 30, 2017 and 2016, respectively, and $597,000 and $539,000 for the six months ended June 30, 2017 and 2016, respectively. The amount of gain (loss) recognized in income as ineffectiveness for derivatives designated in cash flow hedging relationships was $0 for each of the three and six months ended June 30, 2017 and 2016.

Derivatives Not Accounted for as Hedges

The Partnership utilizes petroleum and ethanol commodity contracts, foreign currency derivatives and, prior to the sale of the Partnership’s natural gas marketing and electricity brokerage businesses, natural gas commodity contracts to hedge price and currency risk in certain commodity inventories and physical forward contracts.

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Petroleum and Ethanol Commodity Contracts

The Partnership uses exchange-traded derivative contracts to hedge price risk in certain commodity inventories which do not qualify for fair value hedge accounting or are not designated by the Partnership as fair value hedges. Additionally, the Partnership uses exchange-traded derivative contracts, and occasionally financial forward and OTC swap agreements, to hedge commodity price exposure associated with its physical forward contracts which are not designated by the Partnership as cash flow hedges. These physical forward contracts, to the extent they meet the definition of a derivative, are considered OTC physical forwards and are reflected as derivative assets or derivative liabilities in the consolidated balance sheet. The related exchange-traded derivative contracts (and financial forward and OTC swaps, if applicable) are also reflected as brokerage margin deposits (and derivative assets or derivative liabilities, if applicable) in the consolidated balance sheet, thereby creating an economic hedge. Changes in fair value of these derivative instruments are recognized in the consolidated statement of operations through cost of sales. These exchange-traded derivatives are settled on a daily basis by the Partnership through brokerage margin accounts.

While the Partnership seeks to maintain a position that is substantially balanced within its commodity product purchase and sale activities, it may experience net unbalanced positions for short periods of time as a result of variances in daily purchases and sales and transportation and delivery schedules as well as other logistical issues inherent in the business, such as weather conditions. In connection with managing these positions, the Partnership is aided by maintaining a constant presence in the marketplace. The Partnership also engages in a controlled trading program for up to an aggregate of 250,000 barrels of commodity products at any one point in time. Changes in fair value of these derivative instruments are recognized in the consolidated statement of operations through cost of sales.

The following table presents the gains and losses from the Partnership’s derivative instruments not involved in a hedging relationship recognized in the consolidated statements of operations for the periods presented (in thousands):


	Statement of Gain (Loss)	Three Months Ended				Six Months Ended
Derivatives not designated as	Recognized in	June 30,				June 30,
hedging instruments	Income on Derivatives	2017		2016		2017		2016
Commodity contracts	Cost of sales	$	1,188	$	326	$	2,742	$	(89)
Forward foreign currency contracts	Cost of sales		—		64		—		103
Total		$	1,188	$	390	$	2,742	$	14

Margin Deposits

All of the Partnership’s exchange-traded derivative contracts (designated and not designated) are transacted through clearing brokers. The Partnership deposits initial margin with the clearing brokers, along with variation margin, which is paid or received on a daily basis, based upon the changes in fair value of open futures contracts and settlement of closed futures contracts. Cash balances on deposit with clearing brokers and open equity are presented on a net basis within brokerage margin deposits in the consolidated balance sheets.

Commodity Contracts and Other Derivative Activity

The Partnership’s commodity contracts and other derivative activity include: (i) exchange-traded derivative contracts that are hedges against inventory and either do not qualify for hedge accounting or are not designated in a hedge accounting relationship, (ii) exchange-traded derivative contracts used to economically hedge physical forward contracts, (iii) financial forward and OTC swap agreements used to economically hedge physical forward contracts and (iv) the derivative instruments under the Partnership’s controlled trading program. The Partnership does not take the normal purchase and sale exemption available under ASC 815 for its physical forward contracts.

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The following table presents the fair value of each classification of the Partnership’s derivative instruments and its location in the consolidated balance sheets at June 30, 2017 and December 31, 2016 (in thousands):


		June 30, 2017
		Derivatives		Derivatives Not
		Designated as		Designated as
		Hedging		Hedging
	Balance Sheet Location	Instruments		Instruments		Total
Asset Derivatives:
Exchange-traded derivative contracts	Broker margin deposits	$	4,295	$	52,119	$	56,414
Forward derivative contracts (1)	Derivative assets		—		6,168		6,168
Total asset derivatives		$	4,295	$	58,287	$	62,582

Liability Derivatives:
Exchange-traded derivative contracts	Broker margin deposits	$	(3,758)	$	(44,847)	$	(48,605)
Forward derivative contracts (1)	Derivative liabilities		—		(4,150)		(4,150)
Interest rate swap contracts	Other long-term liabilities		—		(574)		(574)
Total liability derivatives		$	(3,758)	$	(49,571)	$	(53,329)


		December 31, 2016
		Derivatives		Derivatives Not
		Designated as		Designated as
		Hedging		Hedging
	Balance Sheet Location	Instruments		Instruments		Total
Asset Derivatives:
Exchange-traded derivative contracts	Broker margin deposits	$	—	$	60,018	$	60,018
Forward derivative contracts (1)	Derivative assets		—		21,382		21,382
Total asset derivatives		$	—	$	81,400	$	81,400

Liability Derivatives:
Exchange-traded derivative contracts	Broker margin deposits	$	(33,877)	$	(96,831)	$	(130,708)
Forward derivative contracts (1)	Derivative liabilities		—		(27,413)		(27,413)
Interest rate swap contracts	Other long-term liabilities		—		(1,170)		(1,170)
Total liability derivatives		$	(33,877)	$	(125,414)	$	(159,291)

(1)

Forward derivative contracts include the Partnership’s petroleum and ethanol physical and financial forwards and OTC swaps.

Credit Risk

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

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

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Note 9. Fair Value Measurements

The following tables present, by level within the fair value hierarchy, the Partnership’s financial assets and liabilities that were measured at fair value on a recurring basis as of June 30, 2017 and December 31, 2016 (in thousands):


	Fair Value at June 30, 2017
							Cash Collateral
	Level 1		Level 2		Level 3		Netting		Total
Assets:
Forward derivative contracts (1)	$	—	$	4,982	$	706	$	—	$	5,688
Swap agreements and options		—		480		—		—		480
Exchange-traded/cleared derivative instruments (2)		7,809		—		—		1,603		9,412
Pension plans		16,861		—		—		—		16,861
Total assets	$	24,670	$	5,462	$	706	$	1,603	$	32,441

Liabilities:
Forward derivative contracts (1)	$	—	$	(3,352)	$	(644)	$	—	$	(3,996)
Swap agreements and options		—		(154)		—		—		(154)
Interest rate swaps		—		(574)		—		—		(574)
Total liabilities	$	—	$	(4,080)	$	(644)	$	—	$	(4,724)


	Fair Value at December 31, 2016
							Cash Collateral
	Level 1		Level 2		Level 3		Netting		Total
Assets:
Forward derivative contracts (1)	$	—	$	18,972	$	1,683	$	—	$	20,655
Swap agreements and options		—		727		—		—		727
Exchange-traded/cleared derivative instruments (2)		(70,690)		—		—		98,344		27,654
Pension plans		16,777		—		—		—		16,777
Total assets	$	(53,913)	$	19,699	$	1,683	$	98,344	$	65,813

Liabilities:
Forward derivative contracts (1)	$	—	$	(25,097)	$	(2,054)	$	—	$	(27,151)
Swap agreements and options		—		(262)		—		—		(262)
Interest rate swaps		—		(1,170)		—		—		(1,170)
Total liabilities	$	—	$	(26,529)	$	(2,054)	$	—	$	(28,583)

(1)

Forward derivative contracts include the Partnership’s petroleum and ethanol physical and financial forwards and OTC swaps.

(2)

Amount includes the effect of cash balances on deposit with clearing brokers.

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

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The carrying value of the inventory qualifying for fair value hedge accounting approximates fair value due to adjustments for changes in fair value of the hedged item. The fair values of the derivatives used by the Partnership are disclosed in Note 8.

The determination of the fair values above incorporates factors including not only the credit standing of the counterparties involved, but also the impact of the Partnership’s nonperformance risks on its liabilities.

The Partnership estimates the fair values of its 6.25% senior notes and 7.00% senior notes using a combination of quoted market prices for similar financing arrangements and expected future payments discounted at risk-adjusted rates, which are considered Level 2 inputs. The fair values of the 6.25% senior notes and 7.00% senior notes, estimated by observing market trading prices of the 6.25% senior notes and 7.00% senior notes, respectively, were as follows (in thousands):


	June 30, 2017					December 31, 2016
	Face			Fair		Face		Fair
	Value			Value		Value		Value
6.25% senior notes		$	375,000	$	376,875	$	375,000	$	361,163
7.00% senior notes		$	300,000	$	300,750	$	300,000	$	289,500

Level 3 Information

The values of the Level 3 derivative contracts were calculated using market approaches based on a combination of observable and unobservable market inputs, including published and quoted NYMEX, CME, ICE, New York Harbor and third-party pricing information for a component of the underlying instruments as well as internally developed assumptions where there is little, if any, published or quoted prices or market activity. The unobservable inputs used in the measurement of the Level 3 derivative contracts include estimates for location basis, transportation and throughput costs net of an estimated margin for current market participants. The estimates for these inputs for crude oil were $0.20 to $3.00 per barrel and $4.05 to $6.50 per barrel as of June 30, 2017 and December 31, 2016, respectively. The estimates for these inputs for propane were $0 to $9.24 per barrel and $4.20 to $10.50 per barrel as of June 30, 2017 and December 31, 2016, respectively. Gains and losses recognized in earnings (or changes in net assets) are disclosed in Note 8.

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


Significant			Impact on Fair Value
Unobservable Input	Position	Change to Input	Measurement
Location basis	Long	Increase (decrease)	Gain (loss)
Location basis	Short	Increase (decrease)	Loss (gain)
Transportation	Long	Increase (decrease)	Gain (loss)
Transportation	Short	Increase (decrease)	Loss (gain)
Throughput costs	Long	Increase (decrease)	Gain (loss)
Throughput costs	Short	Increase (decrease)	Loss (gain)

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The following table presents a reconciliation of changes in fair value of the Partnership’s derivative contracts classified as Level 3 in the fair value hierarchy at June 30, 2017 (in thousands):


Fair value at December 31, 2016	$	(371)
Derivatives entered into during the period		247
Derivatives sold during the period		(108)
Realized gains (losses) recorded in cost of sales		596
Unrealized gains (losses) recorded in cost of sales		(302)
Fair value at June 30, 2017	$	62

The Partnership’s policy is to recognize transfers between levels with the fair value hierarchy as of the beginning of the reporting period. The Partnership also excludes any activity for derivative instruments that were not classified as Level 3 at either the beginning or end of the reporting period.

Non-Recurring Fair Value Measures

Certain nonfinancial assets and liabilities are measured at fair value on a non-recurring basis and are subject to fair value adjustments in certain circumstances, such as acquired assets and liabilities, losses related to firm non-cancellable purchase commitments or long-lived assets subject to impairment. 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 6 for a discussion of the Partnership’s losses on impairment of assets and Note 5 for assets held for sale.

Note 10. Environmental Liabilities, Asset Retirement Obligations and Renewable Identification Numbers

Environmental Liabilities

The following table presents a summary roll forward of the Partnership’s environmental liabilities at June 30, 2017 (in thousands):


	Balance at						Other		Balance at
	December 31,		Payments		Dispositions		Adjustments		June 30,
Environmental Liability Related to:	2016		2017		2017		2017		2017
Retail gasoline stations	$	58,456	$	(1,342)	$	(1,500)	$	(911)	$	54,703
Terminals		4,609		(53)		—		—		4,556
Total environmental liabilities	$	63,065	$	(1,395)	$	(1,500)	$	(911)	$	59,259
Current portion	$	5,341							$	5,334
Long-term portion		57,724								53,925
Total environmental liabilities	$	63,065							$	59,259

The Partnership’s estimates used in these environmental liabilities are based on all known facts at the time and its assessment of the ultimate remedial action outcomes. Among the many uncertainties that impact the Partnership’s estimates are the necessary regulatory approvals for, and potential modification of, its remediation plans, the amount of data available upon initial assessment of the impact of soil or water contamination, changes in costs associated with environmental remediation services and equipment, relief of obligations through divestitures of sites and the possibility of existing legal claims giving rise to additional claims. Dispositions generally represent relief of legal obligations through the sale of the related property with no retained obligation. Other adjustments generally represent changes in estimates for existing obligations or obligations associated with new sites. Therefore, although the Partnership believes that these environmental liabilities are adequate, no assurances can be made that any costs incurred in excess of these

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environmental liabilities or outside of indemnifications or not otherwise covered by insurance would not have a material adverse effect on the Partnership’s financial condition, results of operations or cash flows.

Asset Retirement Obligations

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

The liability for an asset retirement obligation is recognized on a discounted basis in the year in which it is incurred, and the discount period applied is based on statutory requirements for UST removal or policy. The associated asset retirement costs are capitalized as part of the carrying cost of the asset. The Partnership had approximately $7.8 million and $8.3 million in total asset retirement obligations at June 30, 2017 and December 31, 2016, respectively, which are included in other long-term liabilities in the accompanying balance sheets.

Renewable Identification Numbers (RINs)

A RIN is a serial number assigned to a batch of renewable fuel for the purpose of tracking its production, use and trading as required by the U.S. Environmental Protection Agency’s (“EPA”) Renewable Fuel Standard that originated with the Energy Policy Act of 2005 and modified by the Energy Independence and Security Act of 2007. To evidence that the required volume of renewable fuel is blended with gasoline and diesel motor vehicle fuels, obligated parties must retire sufficient RINs to cover their Renewable Volume Obligation (“RVO”). The Partnership’s EPA obligations relative to renewable fuel reporting are largely limited to the foreign gasoline and diesel that the Partnership may choose to import and a small amount of blending operations at certain facilities. As a wholesaler of transportation fuels through its terminals, the Partnership separates RINs from renewable fuel through blending with gasoline and can use those separated RINs to settle its RVO. While the annual compliance period for the RVO is a calendar year and the settlement of the RVO typically occurs by March 31 of the following year, the settlement of the RVO can occur, under certain EPA deferral actions, more than one year after the close of the compliance period.

The Partnership’s Wholesale segment’s operating results may be sensitive to the timing associated with its RIN position relative to its RVO at a point in time, and the Partnership may recognize a mark-to-market liability for a shortfall in RINs at the end of each reporting period. To the extent that the Partnership does not have a sufficient number of RINs to satisfy the RVO as of the balance sheet date, the Partnership charges cost of sales for such deficiency based on the market price of the RINs as of the balance sheet date and records a liability representing the Partnership’s obligation to purchase RINs. The Partnership’s RVO deficiency was immaterial at June 30, 2017 and $0.2 million at December 31, 2016.

The Partnership may enter into RIN forward purchase and sales commitments. Total losses from firm non-cancellable commitments at June 30, 2017 and December 31, 2016 were immaterial.

Note 11. Related Party Transactions

The Partnership is a party to a Second Amended and Restated Services Agreement with Global Petroleum Corp. (“GPC”), an affiliate of the Partnership that is 100% owned by members of the Slifka family, pursuant to which the Partnership provides GPC with certain tax, accounting, treasury, legal, information technology, human resources and financial operations support services for which GPC pays the Partnership a monthly services fee at an agreed amount subject to the approval by the Conflicts Committee of the board of directors of the General Partner. The Second Amended and Restated Services Agreement is for an indefinite term and any party may terminate some or all of the

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services upon ninety (90) days’ advanced written notice. As of June 30, 2017, no such notice of termination was given by GPC.

The General Partner employs substantially all of the Partnership’s employees, except for most of its gasoline station and convenience store employees, who are employed by GMG. The Partnership reimburses the General Partner for expenses incurred in connection with these employees. These expenses, including payroll, payroll taxes and bonus accruals, were $24.7 million and $23.5 million for the three months ended June 30, 2017 and 2016, respectively, and $49.3 million and $49.2 million for the six months ended June 30, 2017 and 2016, respectively. The Partnership also reimburses the General Partner for its contributions under the General Partner’s 401(k) Savings and Profit Sharing Plans and the General Partner’s qualified and non-qualified pension plans.

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


	June 30,		December 31,
	2017		2016
Receivables from GPC	$	72	$	6
Receivables from the General Partner (1)		3,774		3,137
Total	$	3,846	$	3,143

(1)

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

In addition, for the three and six months ended June 30, 2017, the Partnership paid members of the General Partner for certain costs incurred in connection with a compensation funding agreement. See Note 12, “Long-Term Incentive Plan–Repurchase Program.”

Note 12. Long-Term Incentive Plan

The Partnership has a Long Term Incentive Plan, as amended (the “LTIP”), whereby a total of 4,300,000 common units were authorized for delivery with respect to awards under the LTIP. The LTIP provides for awards to employees, consultants and directors of the General Partner and employees and consultants of affiliates of the Partnership who perform services for the Partnership. The LTIP allows for the award of options, unit appreciation rights, restricted units, phantom units, distribution equivalent rights, unit awards and substitute awards. Awards granted pursuant to the LTIP vest pursuant to the terms of the grant agreements. Please read Note 15 of Notes to Consolidated Financial Statements in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2016 for additional information on the LTIP.

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


		Weighted
	Number of	Average
	Non-vested	Grant Date
	Units	Fair Value ($)
Outstanding non—vested units at December 31, 2016	571,554	38.56
Vested	(10,659)	35.94
Forfeited	(54,977)	38.30
Outstanding non—vested units at June 30, 2017	505,918	38.65

The Partnership recorded total compensation expense related to the outstanding awards of $0.9 million and $1.1 million for the three months ended June 30, 2017 and 2016, respectively, and $2.0 million and $2.2 million for the six months ended June 30, 2017 and 2016, respectively, which is included in selling, general and administrative expenses

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in the accompanying consolidated statements of operations. During the three and six months ended June 30, 2017, 3,774 and 54,977 phantom units, respectively, were forfeited, the majority of which are related to phantom unit awards granted in 2013. As the Partnership’s assumption for forfeitures at the time of grant was zero based on service history, the Partnership reversed compensation expenses related to the forfeitures in the amount of $0.2 million and $1.4 million for the three and six months ended June 30, 2017, respectively, which is included in selling, general and administrative expenses in the accompanying consolidated statement of operations.

The total compensation cost related to the non-vested awards not yet recognized at June 30, 2017 was approximately $7.1 million and is expected to be recognized ratably over the remaining requisite service periods.

Repurchase Program

In May 2009, the board of directors of the General Partner authorized the repurchase of the Partnership’s common units (the “Repurchase Program”) for the purpose of meeting the General Partner’s anticipated obligations to deliver common units under the LTIP and meeting the General Partner’s obligations under existing employment agreements and other employment related obligations of the General Partner (collectively, the “General Partner’s Obligations”). The General Partner is authorized to acquire up to 1,242,427 of its common units in the aggregate over an extended period of time, consistent with the General Partner’s Obligations. Common units may be repurchased from time to time in open market transactions, including block purchases, or in privately negotiated transactions. Such authorized unit repurchases may be modified, suspended or terminated at any time and are subject to price and economic and market conditions, applicable legal requirements and available liquidity. Since the Repurchase Program was implemented, the General Partner repurchased 838,505 common units pursuant to the Repurchase Program for approximately $24.8 million, none of which were purchased during the three and six months ended June 30, 2017.

In June 2009, the Partnership and the General Partner entered into the Global GP LLC Compensation Funding Agreement (the “Agreement”) whereby the Partnership and the General Partner established obligations and protocol for (i) the funding, management and administration of a compensation funding account and underlying General Partner’s Obligations, and (ii) the holding and disposition by the General Partner of common units acquired in accordance with the Agreement for such purposes as otherwise set forth in the Agreement. The Agreement requires the Partnership to fund costs that the General Partner incurs in connection with performance of the Agreement. In accordance with the Agreement, in June 2017, the Partnership paid members of the General Partner approximately $0.8 million in the aggregate for certain costs incurred in connection with the Agreement, which is included in selling, general and administrative expenses in the accompanying consolidated statements of operations for each of the three and six months ended June 30, 2017.

Note 13. Partners’ Equity and Cash Distributions

Partners’ Equity

Partners’ equity at June 30, 2017 consisted of 33,995,563 common units issued, including 7,433,829 common units held by affiliates of the General Partner, including directors and executive officers, collectively representing a 99.33% limited partner interest in the Partnership, and 230,303 general partner units representing a 0.67% general partner interest in the Partnership. There have been no changes to partners’ equity during the six months ended June 30, 2017.

Cash Distributions

The Partnership intends to make 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

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(Unaudited)

any potential default or Event of Default, as defined in the Credit Agreement, occurs or would result from the cash distribution. The indentures governing the Partnership’s outstanding senior notes also limit the Partnership’s ability to make distributions to its unitholders in certain circumstances.

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

The Partnership will make distributions of Available Cash from distributable cash flow for any quarter in the following manner: 99.33% to the common unitholders, pro rata, and 0.67% 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:


			Marginal Percentage
	Total Quarterly Distribution		Interest in Distributions
	Target Amount		Unitholders		General Partner
First Target Distribution		up to $0.4625	99.33	%	0.67	%
Second Target Distribution		above $0.4625 up to $0.5375	86.33	%	13.67	%
Third Target Distribution		above $0.5375 up to $0.6625	76.33	%	23.67	%
Thereafter		above $0.6625	51.33	%	48.67	%

The Partnership paid the following cash distributions during 2017 (in thousands, except per unit data):


	Earned for the	Per Unit
Cash Distribution	Quarter	Cash		Common		General		Incentive		Total Cash
Payment Date	Ended	Distribution		Units		Partner		Distribution		Distribution
2/14/2017	12/31/16	$	0.4625	$	15,723	$	106	$	—	$	15,829
5/15/2017	03/31/17		0.4625		15,723		106		—		15,829

In addition, on July 28, 2017, the board of directors of the General Partner declared a quarterly cash distribution of $0.4625 per unit ($1.85 per unit on an annualized basis) on all of its outstanding common units for the period from April 1, 2017 through June 30, 2017. On August 14, 2017, the Partnership will pay this cash distribution to its unitholders of record as of the close of business on August 9, 2017.

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(Unaudited)

Note 14. Unitholders’ Equity

At-the-Market Offering Program

On May 19, 2015, the Partnership entered into an equity distribution agreement pursuant to which the Partnership may sell from time to time through its sales agents, following a standard due diligence effort, the Partnership’s common units having an aggregate offering price of up to $50.0 million. Sales of the common units, if any, will be made by any method permitted by law deemed to be an “at-the-market” offering, including ordinary brokers’ transactions through the facilities of the New York Stock Exchange, to or through a market maker, or directly on or through an electronic communication network, a “dark pool” or any similar market venue, at market prices, in block transactions, or as otherwise agreed upon by the Partnership and one or more of its sales agents.

The Partnership may also sell common units to one or more of its sales agents as principal for its own account at a price to be agreed upon at the time of sale. Any sale of common units to a sales agent as principal would be pursuant to the terms of a separate agreement between the Partnership and such sales agent.

The Partnership intends to use the net proceeds from any sales pursuant to the at-the-market offering program, after deducting the sales agents’ commissions and the Partnership’s offering expenses, for general partnership purposes, which may include, among other things, repayment of indebtedness, acquisitions and capital expenditures.

The sales agents and/or affiliates of each of the sales agents have, from time to time, performed, and may in the future perform, various financial advisory and commercial and investment banking services for the Partnership and its affiliates, for which they have received and in the future will receive customary compensation and expense reimbursement. Affiliates of the sales agents are lenders under the Partnership’s credit facility and, accordingly, may receive a portion of the net proceeds from this offering if and to the extent any proceeds are used to reduce outstanding borrowings under the Partnership’s credit facility.

No common units have been sold by the Partnership pursuant to the at-the-market offering program since inception.

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Note 15. Segment Reporting

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


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2017		2016		2017		2016
Wholesale Segment:
Sales
Gasoline and gasoline blendstocks	$	461,063	$	594,411	$	966,767	$	937,140
Crude oil (1)		143,143		160,595		246,671		309,097
Other oils and related products (2)		340,463		318,123		957,030		737,132
Total	$	944,669	$	1,073,129	$	2,170,468	$	1,983,369
Product margin
Gasoline and gasoline blendstocks	$	18,608	$	26,612	$	33,993	$	42,974
Crude oil (1)		4,761		(9,648)		11,653		(12,021)
Other oils and related products (2)		7,828		15,804		37,701		41,053
Total	$	31,197	$	32,768	$	83,347	$	72,006
Gasoline Distribution and Station Operations Segment:
Sales
Gasoline	$	859,747	$	815,634	$	1,627,383	$	1,431,737
Station operations (3)		87,857		101,058		163,453		186,243
Total	$	947,604	$	916,692	$	1,790,836	$	1,617,980
Product margin
Gasoline	$	79,283	$	66,999	$	146,438	$	132,386
Station operations (3)		43,242		49,267		82,137		92,192
Total	$	122,525	$	116,266	$	228,575	$	224,578
Commercial Segment:
Sales	$	197,257	$	156,378	$	399,010	$	295,662
Product margin	$	4,124	$	5,480	$	8,313	$	12,390
Combined sales and Product margin:
Sales	$	2,089,530	$	2,146,199	$	4,360,314	$	3,897,011
Product margin (4)	$	157,846	$	154,514	$	320,235	$	308,974
Depreciation allocated to cost of sales		(22,484)		(25,172)		(44,846)		(49,573)
Combined gross profit	$	135,362	$	129,342	$	275,389	$	259,401

(1)

Crude oil consists of the Partnership’s crude oil sales and revenue from its logistics activities.

(2)

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

(3)

Station operations consist of convenience store sales, rental income and sundries.

(4)

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

Approximately 124 million gallons and 121 million gallons of the GDSO segment’s sales for the three months ended June 30, 2017 and 2016, respectively, and 238 million gallons and 232 million gallons of the GDSO segment’s sales for the six months ended June 30, 2017 and 2016, respectively, were supplied from petroleum products and renewable fuels sourced by the Wholesale segment. Except for natural gas (prior to the sale of the Partnership’s natural gas marketing and electricity brokerage businesses in February 2017), predominantly all of the Commercial segment’s sales are sourced by the Wholesale segment. These intra-segment sales are not reflected as sales in the Wholesale segment as they are eliminated.

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


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2017		2016		2017		2016
Combined gross profit	$	135,362	$	129,342	$	275,389	$	259,401
Operating costs and expenses not allocated to operating segments:
Selling, general and administrative expenses		34,679		36,640		71,466		71,624
Operating expenses		71,169		75,891		138,382		148,127
Amortization expense		2,260		2,359		4,521		4,868
Net loss (gain) on sale and disposition of assets		2,381		375		(9,481)		6,480
Long-lived asset impairment		—		2,155		—		2,155
Total operating costs and expenses		110,489		117,420		204,888		233,254
Operating income		24,873		11,922		70,501		26,147
Interest expense		(21,923)		(21,015)		(45,210)		(43,995)
Income tax (expense) benefit		(959)		550		(795)		1,470
Net income (loss)		1,991		(8,543)		24,496		(16,378)
Net loss attributable to noncontrolling interest		383		1,233		824		2,044
Net income (loss) attributable to Global Partners LP	$	2,374	$	(7,310)	$	25,320	$	(14,334)

The Partnership’s foreign assets and foreign sales were immaterial as of and for the three and six months ended June 30, 2017 and 2016.

Segment Assets

The Partnership’s terminal assets are allocated to the Wholesale and Commercial segments, and its retail gasoline stations are allocated to the GDSO segment. Due to the commingled nature and uses of the remainder of the Partnership’s assets, it is not reasonably possible for the Partnership to allocate these assets among its reportable segments.

The table below presents total assets by reportable segment at June 30, 2017 and December 31, 2016 (in thousands):


		Wholesale		Commercial		GDSO		Unallocated		Total
June 30, 2017	$	651,086	$	117	$	1,241,702	$	304,675	$	2,197,580
December 31, 2016	$	830,662	$	134	$	1,294,568	$	438,656	$	2,564,020

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 refined petroleum products, crude oil and ethanol to resellers and refiners. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income.

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

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

On July 1, 2015 the Partnership commenced business in Canada through its wholly owned Canadian subsidiary, Global Partners Energy Canada ULC (“GPEC”). GPEC predominantly consists of sourcing crude oil and other petroleum based products for sale to the Partnership and customers in Canada. GPEC is a taxable entity for Canadian corporate income and branch taxes. In its first year of operations, GPEC realized a pre-tax loss generating a net operating loss that might be used to offset future taxable income when GPEC operates at a profit. The Partnership recognizes deferred tax assets to the extent that the recoverability of these assets satisfies the “more likely than not” recognition criteria in accordance with the accounting guidance regarding income taxes. Based upon projections of future taxable income, limited capital assets and market conditions, the Partnership has provided a full valuation allowance against the GPEC deferred tax asset.

The Partnership recognizes deferred tax assets to the extent that the recoverability of these assets satisfies the “more likely than not” recognition criteria in accordance with the accounting guidance regarding income taxes. Based upon projections of future taxable income, the Partnership believes that the recorded deferred tax assets will be realized.

The Partnership computed its tax provision for the three and six months ended June 30, 2017 based upon the year-to-date effective tax rate as opposed to an estimated annual effective tax rate. The Partnership concluded that the year-to-date effective tax rate is the most appropriate method to use for the three and six months ended June 30, 2017, given a reliable estimate of the annual effective tax rate cannot be made.

Unrecognized tax benefits represent uncertain tax positions for which reserves have been established. At each of June 30, 2017 and December 31, 2016, the Partnership had $1.4 million of unrecognized tax benefits, of which all would favorably impact the effective tax rate if recognized.

GMG files income tax returns in the United States and various state jurisdictions. With few exceptions, the Partnership is subject to income tax examination by tax authorities for all years dated back to 2013.

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Note 17. Changes in Accumulated Other Comprehensive Loss

The following table presents the changes in accumulated other comprehensive loss by component for the periods presented (in thousands):


	Pension
Three Months Ended June 30, 2017	Plan		Derivatives		Total
Balance at March 31, 2017	$	(3,950)	$	(774)	$	(4,724)
Other comprehensive income before reclassifications of gain (loss)		277		199		476
Amount of (loss) gain reclassified from accumulated other comprehensive income		(27)		—		(27)
Total comprehensive income		250		199		449
Balance at June 30, 2017	$	(3,700)	$	(575)	$	(4,275)

	Pension
Six Months Ended June 30, 2017	Plan		Derivatives		Total
Balance at December 31, 2016	$	(4,269)	$	(1,172)	$	(5,441)
Other comprehensive income before reclassifications of gain (loss)		623		597		1,220
Amount of (loss) gain reclassified from accumulated other comprehensive income		(54)		—		(54)
Total comprehensive income		569		597		1,166
Balance at June 30, 2017	$	(3,700)	$	(575)	$	(4,275)

Amounts are presented prior to the income tax effect on other comprehensive income. Given the Partnership’s partnership status for federal income tax purposes, the effective tax rate is immaterial.

Note 18. Supplemental Cash Flow Information

The following table presents cash flow supplemental information for the periods presented (in thousands):


	Six Months Ended
	June 30,
	2017		2016
Borrowings from working capital revolving credit facility	$	592,100	$	804,300
Payments on working capital revolving credit facility		(767,600)		(683,600)
Net (payments on) borrowings from working capital revolving credit facility	$	(175,500)	$	120,700
Borrowings from revolving credit facility	$	—	$	20,300
Payments on revolving credit facility		(16,000)		(75,900)
Net payments on revolving credit facility	$	(16,000)	$	(55,600)

Note 19. 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 10 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

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coverage and deductibles as its general partner believes are reasonable and prudent. However, the Partnership can provide no assurance that this insurance will be adequate to protect it from all material expenses related to potential future claims or that these levels of insurance will be available in the future at economically acceptable prices.

Other

The Partnership determined that gasoline loaded from certain loading bays at one of its terminals did not contain the necessary additives as a result of an IT-related configuration error. The error was corrected and all gasoline being sold at the terminal now contains the appropriate additives. Based upon current information, the Partnership believes approximately 14 million gallons of gasoline were impacted. The Partnership has notified the EPA of this error. As a result of this error, the Partnership could be subject to fines, penalties and other related claims, including customer claims.

In February 2016, the Partnership received a request for information from the EPA seeking certain information regarding its Albany terminal in order to assess its compliance with the Clean Air Act (the “CAA”). The information requested generally related to crude oil received by, stored at and shipped from the Partnership’s petroleum product transloading facility in Albany, New York (the “Albany Terminal”), including its composition, control devices for emissions and various permitting-related considerations. The Albany Terminal is a 63-acre licensed, permitted and operational stationary bulk petroleum storage and transfer terminal that currently consists of petroleum product storage tanks, along with truck, rail and marine loading facilities, for the storage, blending and distribution of various petroleum and related products, including gasoline, ethanol, distillates, heating and crude oils. No violations were alleged in the request for information. The Partnership submitted responses and documentation, in March and April 2016, to the EPA in accordance with the EPA request. On August 2, 2016, the Partnership received a Notice of Violation (“NOV”) from the EPA, alleging that permits for the Albany Terminal, issued by the New York State Department of Environmental Conservation (“NYSDEC”) between August 9, 2011 and November 7, 2012, violated the CAA and the federally enforceable New York State Implementation Plan (“SIP”) by increasing throughput of crude oil at the Albany Terminal without complying with the New Source Review (“NSR”) requirements of the SIP. The applicable permits issued by the NYSDEC to the Partnership in 2011 and 2012 specifically authorize the Partnership to increase the throughput of crude oil at the Albany Terminal. According to the allegations in the NOV, the NYSDEC permits should have been regulated as a major modification under the NSR program, requiring additional emission control measures and compliance with other NSR requirements. The NYSDEC has not alleged that the Partnership’s permits were subject to the NSR program. The CAA authorizes the EPA to take enforcement action in response to violations of the New York SIP seeking compliance and penalties. The Partnership believes that the permits issued by the NYSDEC comply with the CAA and applicable State air permitting requirements and that no material violation of law has occurred. The Partnership disputes the claims alleged in the NOV and responded to the EPA in September, 2016. The Partnership met with the EPA and provided additional information at the agency’s request. On December 16, 2016, the EPA proposed a Settlement Agreement in a letter to the Partnership relating to the allegations in the NOV. On January 17, 2017, the Partnership responded to the EPA indicating that the EPA had failed to explain or provide support for its allegations and that the EPA needed to better explain its positions and the evidence on which it was relying. The EPA did not respond with such evidence but instead requested that the Partnership enter into a further tolling agreement. The Partnership has signed a number of tolling agreements with respect to this matter and such agreements currently extend through October 31, 2017. To date, the EPA has not taken any further action with respect to the NOV.

By letter dated October 5, 2015, the Partnership received a notice of intent to sue (the “October NOI”), which supersedes and replaces a prior notice of intent to sue that the Partnership received on September 1, 2015 (the “September NOI”) from Earthjustice, an environmental advocacy organization on behalf of the County of Albany, New York, a public housing development owned and operated by the Albany Housing Authority and certain environmental organizations, related to alleged violations of the CAA, particularly with respect to crude oil operations at the Albany Terminal. The October NOI superseded and replaced the September NOI to add two additional environmental advocacy organizations and to revise the relief sought and the description of the alleged CAA violations.

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On February 3, 2016, after the NYSDEC chose not to act on the allegations, Earthjustice and the other entities identified in the October NOI filed suit against the Partnership in federal court in Albany under the citizen suit provisions of the CAA. In summary, this lawsuit alleges that certain of the Partnership’s operations at the Albany Terminal are in violation of the CAA. The plaintiffs seek, among other things, relief that would compel the Partnership both to apply for what the plaintiffs contend is the applicable permit under the CAA, and to install additional pollution controls. In addition, the plaintiffs seek to prohibit the Albany Terminal from receiving, storing, handling, and marine loading certain types of Bakken crude oil and to require payment of a civil penalty of $37,500 for each day the Partnership as operated the Albany Terminal in violation of the CAA. The Partnership believes that it has meritorious defenses against all allegations. On February 26, 2016, the Partnership filed a motion to dismiss the CAA action. No decision has yet been issued by the Court and all discovery and other litigation activity is stayed pending a decision by the Court on the motion to dismiss.

By letter dated January 25, 2017, the Partnership received a notice of intent to sue (the “2017 NOI”) from Earthjustice related to alleged violations of the CAA; specifically alleging that the Partnership was operating the Albany Terminal without a valid CAA Title V Permit. On February 9, 2017, the Partnership responded to Earthjustice advising that the 2017 NOI was without factual or legal merit and that the Partnership would move to dismiss any action commenced by Earthjustice. No action was taken by either the EPA or the NYSDEC with regard to the Earthjustice allegations. At this time, there has been no further action taken by Earthjustice. Neither the EPA nor the NYSDEC has followed up on the NOI. The Albany Terminal is currently operating pursuant to its Title V Permit. The Partnership believes that it has meritorious defenses against all allegations.

On May 29, 2015 and in connection with a commercial dispute with Tethys Trading Company LLC (“Tethys”), the Partnership received a notice from Tethys alleging a default under, and purporting to terminate, the Partnership’s contract with Tethys for crude oil services at the Partnership’s Oregon facility. However, the Partnership does not believe Tethys had the right to terminate the contract, and the Partnership will continue to investigate and determine the appropriate action to take to enforce its rights under the agreement.

On March 26, 2015, the Partnership received a Notice of Non-Compliance (“NON”) from the Massachusetts Department of Environmental Protection (“DEP”) with respect to the Revere terminal (the “Revere Terminal”) located in Boston Harbor in Revere, Massachusetts, alleging certain violations of the National Pollutant Discharge Elimination System Permit (“NPDES Permit”) related to storm water discharges. The NON required the Partnership to submit a plan to remedy the reported violations of the NPDES Permit. The Partnership has responded to the NON with a plan and has implemented modifications to the storm water management system at the Revere Terminal in accordance with the plan. The Partnership has requested that the DEP acknowledge completion of the required modifications to the storm water management system in satisfaction of the NON. While no response has yet been received, the Partnership believes that compliance with the NON has been achieved, and implementation of the plan will have no material impact on its operations.

The Partnership received letters from the EPA dated November 2, 2011 and March 29, 2012, containing requirements and testing orders (collectively, the “Requests for Information”) for information under the CAA. The Requests for Information were part of an EPA investigation to determine whether the Partnership has violated sections of the CAA at certain of its terminal locations in New England with respect to residual oil and asphalt. On June 6, 2014, a NOV was received from the EPA, alleging certain violations of its Air Emissions License issued by the Maine Department of Environmental Protection, based upon the test results at the South Portland, Maine terminal. The Partnership met with and provided additional information to the EPA with respect to the alleged violations. On April 7, 2015, the EPA issued a Supplemental Notice of Violation (the “Supplemental NOV”) modifying the allegations of violations of the terminal’s Air Emissions License. The Partnership has responded to the Supplemental NOV and is engaged in further negotiations with the EPA. A tolling agreement was executed with the United States on December 1, 2015, which has currently been extended through October 31, 2017. While the Partnership does not believe that a

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material violation has occurred, and it contests the allegations presented in the NOV and Supplemental NOV, the Partnership does not believe any adverse determination in connection with the NOV would have a material impact on its operations.

Note 20. New Accounting Standards

Except as disclosed below, there have been no developments to recently issued accounting standards, including the expected dates of adoption and estimated effects on the Partnership’s consolidated financial statements, from those disclosed in the Partnership’s 2016 Annual Report on Form 10-K, except for the following:

Accounting Standards or Updates Recently Adopted

In January 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2017-04, “Intangibles-Goodwill and Other.” This standard eliminates step two from the goodwill impairment test, and instead requires an entity to recognize a goodwill impairment charge for the amount by which the goodwill carrying amount exceeds the reporting unit’s fair value. This standard is effective for interim and annual goodwill impairment tests in fiscal years beginning after December 15, 2019, and early adoption is permitted. This standard must be applied on a prospective basis. The Partnership adopted this standard on January 1, 2017. The adoption of this standard did not have a material impact on the Partnership’s consolidated financial statements.

In March 2016, the FASB issued ASU 2016-09, “Compensation-Stock Compensation: Improvements to Employee Share-Based Payment Accounting.” This standard simplifies several aspects of the accounting for share-based payment award transactions, including accounting for income taxes and classification of excess tax benefits on the statement of cash flows, forfeitures and minimum statutory tax withholding requirements. This standard is effective for annual periods beginning after December 15, 2016 and interim periods within those annual periods. Early adoption is permitted for any interim or annual period. The Partnership adopted this standard on January 1, 2017. The adoption of this standard did not have a material impact on the Partnership’s consolidated financial statements.

In March 2016, the FASB issued ASU 2016-05, “Derivatives and Hedging: Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships.” This standard clarifies that a change in the counterparty to a derivative instrument that has been designated as a hedging instrument does not, in and of itself, require dedesignation of that hedging relationship provided that all other hedge accounting criteria continue to be met. This standard is effective for fiscal years beginning after December 15, 2016 and interim periods within those fiscal years. Early adoption is permitted, including adoption in an interim period. The Partnership adopted this standard on January 1, 2017. The adoption of this standard did not have a material impact on the Partnership’s consolidated financial statements.

In July 2015, the FASB issued ASU 2015-11, “Simplifying the Measurement of Inventory,” which requires an entity to measure inventory within the scope of the amendment at the lower of cost and net realizable value. Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. This standard is effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years. The Partnership adopted this standard on January 1, 2017. The adoption of this standard did not have a material impact on the Partnership’s consolidated financial statements.

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Accounting Standards or Updates Not Yet Effective

In January 2017, the FASB issued ASU 2017-01, “Business Combinations: Clarifying the Definition of a Business.” This standard clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. This standard is effective for annual periods beginning after December 15, 2017 and interim periods within those annual periods. The Partnership is assessing the impact this standard will have on its consolidated financial statements.

In January 2016, the FASB issued ASU 2016-01, “Financial Instruments - Recognition and Measurement of Financial Assets and Financial Liabilities”. This standard revises the classification and measurement of investments in certain equity investments and the presentation of certain fair value changes for certain financial liabilities measured at fair value. This standard also requires the change in fair value of many equity investments to be recognized in net income. This standard is effective for interim and annual periods beginning after December 15, 2017, with early adoption permitted. The adoption of this standard is not expected to have a material impact on the Partnership’s consolidated financial statements.

In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers” (“ASU 2014-09”) and has modified the standard thereafter. This standard, as amended, replaces existing revenue recognition rules with a comprehensive revenue measurement and recognition standard and expanded disclosure requirements. ASU 2014-09, as amended, becomes effective for annual reporting periods beginning after December 15, 2017, at which point the Partnership plans to adopt the standard. The Partnership is evaluating the impact this standard will have on its consolidated financial statements. To perform the evaluation, the Partnership established a cross-functional implementation team consisting of representatives from across all of the Partnership’s operating segments. Based on initial evaluation efforts performed, the Partnership expects that a portion of its current and prospective revenue will be outside the scope of the standard. Of the Partnership’s revenue recognized for the year ended December 31, 2016, approximately 40% originated as forward physical contracts (within the Wholesale and Commercial segments) which are accounted for as derivatives and are outside the scope of ASU 2014-09. Through the second quarter of 2017, the Partnership’s evaluation has focused on reviewing customer contracts within the Wholesale and Commercial segments. The Partnership expects to complete this contract review along with the review of customer contracts within the GDSO segment during the third quarter of 2017.

The FASB allows two adoption methods under ASU 2014-09. Under one method, an entity will apply the rules to contracts in all reporting periods presented, subject to certain allowable exceptions. Under the other method, an entity will apply the rules to all contracts existing as of January 1, 2018, recognizing in beginning retained earnings an adjustment for the cumulative effect of the change and providing additional disclosures comparing results to previous rules (“modified retrospective method”). The Partnership currently intends to adopt the modified retrospective method.

Note 21. Subsequent Event

Distribution—On July 28, 2017, the board of directors of the General Partner declared a quarterly cash distribution of $0.4625 per unit ($1.85 per unit on an annualized basis) for the period from April 1, 2017 through June 30, 2017. On August 14, 2017, the Partnership will pay this cash distribution to its unitholders of record as of the close of business on August 9, 2017.

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Note 22. Supplemental Guarantor Condensed Consolidating Financial Statements

The Partnership’s wholly owned subsidiaries, other than GLP Finance, are guarantors of senior notes issued by the Partnership and GLP Finance. As such, the Partnership is subject to the requirements of Rule 3-10 of Regulation S-X of the SEC regarding financial statements of guarantors and issuers of registered guaranteed securities. The Partnership presents condensed consolidating financial information for its subsidiaries within the notes to consolidated financial statements in accordance with the criteria established for parent companies in the SEC’s Regulation S-X, Rule 3-10(d).

The following condensed consolidating financial information presents the Condensed Consolidating Balance Sheets as of June 30, 2017 and December 31, 2016, the Condensed Consolidating Statements of Operations for the three and six months ended June 30, 2017 and 2016 and the Condensed Consolidating Statements of Cash Flows for the six months ended June 30, 2017 and 2016 of the Partnership’s 100% owned guarantor subsidiaries, the non-guarantor subsidiary and the eliminations necessary to arrive at the information for the Partnership on a consolidated basis. The principal elimination entries eliminate investments in subsidiaries and intercompany balances and transactions.

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Condensed Consolidating Balance Sheet

June 30, 2017

(In thousands)


	(Issuer)		Non-
	Guarantor		Guarantor
	Subsidiaries		Subsidiary		Eliminations		Consolidated
Assets
Current assets:
Cash and cash equivalents	$	5,083	$	839	$	—	$	5,922
Accounts receivable, net		260,442		331		133		260,906
Accounts receivable - affiliates		3,846		133		(133)		3,846
Inventories		370,364		—		—		370,364
Brokerage margin deposits		9,413		—		—		9,413
Derivative assets		6,168		—		—		6,168
Prepaid expenses and other current assets		73,904		257		—		74,161
Total current assets		729,220		1,560		—		730,780
Property and equipment, net		1,045,217		9,367		—		1,054,584
Intangible assets, net		59,965		—		—		59,965
Goodwill		291,843		—		—		291,843
Other assets		60,408		—		—		60,408
Total assets	$	2,186,653	$	10,927	$	—	$	2,197,580

Liabilities and partners' equity
Current liabilities:
Accounts payable	$	195,487	$	247	$	—	$	195,734
Accounts payable - affiliates		(74)		74		—		—
Working capital revolving credit facility - current portion		99,100		—		—		99,100
Environmental liabilities - current portion		5,334		—		—		5,334
Trustee taxes payable		102,330		—		—		102,330
Accrued expenses and other current liabilities		54,227		89		—		54,316
Derivative liabilities		4,150		—		—		4,150
Total current liabilities		460,554		410		—		460,964
Working capital revolving credit facility - less current portion		150,000		—		—		150,000
Revolving credit facility		200,700		—		—		200,700
Senior notes		660,463		—		—		660,463
Environmental liabilities - less current portion		53,925		—		—		53,925
Financing obligations		152,479		—		—		152,479
Deferred tax liabilities		65,338		—		—		65,338
Other long-term liabilities		61,046		—		—		61,046
Total liabilities		1,804,505		410		—		1,804,915

Partners' equity
Global Partners LP equity		382,148		6,341		—		388,489
Noncontrolling interest		—		4,176		—		4,176
Total partners' equity		382,148		10,517		—		392,665
Total liabilities and partners' equity	$	2,186,653	$	10,927	$	—	$	2,197,580

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Condensed Consolidating Balance Sheet

December 31, 2016

(In thousands)


	(Issuer)		Non-
	Guarantor		Guarantor
	Subsidiaries		Subsidiary		Eliminations		Consolidated
Assets
Current assets:
Cash and cash equivalents	$	9,373	$	655	$	—	$	10,028
Accounts receivable, net		420,897		213		250		421,360
Accounts receivable - affiliates		2,865		528		(250)		3,143
Inventories		521,878		—		—		521,878
Brokerage margin deposits		27,653		—		—		27,653
Derivative assets		21,382		—		—		21,382
Prepaid expenses and other current assets		69,872		150		—		70,022
Total current assets		1,073,920		1,546		—		1,075,466
Property and equipment, net		1,087,964		11,935		—		1,099,899
Intangible assets, net		65,013		—		—		65,013
Goodwill		294,768		—		—		294,768
Other assets		28,874		—		—		28,874
Total assets	$	2,550,539	$	13,481	$	—	$	2,564,020

Liabilities and partners' equity
Current liabilities:
Accounts payable	$	320,003	$	259	$	—	$	320,262
Working capital revolving credit facility - current portion		274,600		—		—		274,600
Environmental liabilities - current portion		5,341		—		—		5,341
Trustee taxes payable		101,166		—		—		101,166
Accrued expenses and other current liabilities		70,262		181		—		70,443
Derivative liabilities		27,413		—		—		27,413
Total current liabilities		798,785		440		—		799,225
Working capital revolving credit facility - less current portion		150,000		—		—		150,000
Revolving credit facility		216,700		—		—		216,700
Senior notes		659,150		—		—		659,150
Environmental liabilities - less current portion		57,724		—		—		57,724
Financing obligations		152,444		—		—		152,444
Deferred tax liabilities		66,054		—		—		66,054
Other long-term liabilities		64,882		—		—		64,882
Total liabilities		2,165,739		440		—		2,166,179

Partners' equity
Global Partners LP equity		384,800		7,855		—		392,655
Noncontrolling interest		—		5,186		—		5,186
Total partners' equity		384,800		13,041		—		397,841
Total liabilities and partners' equity	$	2,550,539	$	13,481	$	—	$	2,564,020

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Condensed Consolidating Statement of Operations

Three Months Ended June 30, 2017

(In thousands)


	(Issuer)		Non-
	Guarantor		Guarantor
	Subsidiaries		Subsidiary		Eliminations		Consolidated
Sales	$	2,088,877	$	752	$	(99)	$	2,089,530
Cost of sales		1,953,006		1,261		(99)		1,954,168
Gross profit		135,871		(509)		—		135,362
Costs and operating expenses:
Selling, general and administrative expenses		34,557		122		—		34,679
Operating expenses		70,843		326		—		71,169
Amortization expense		2,260		—		—		2,260
Net loss on sale and disposition of assets		2,381		—		—		2,381
Total costs and operating expenses		110,041		448		—		110,489
Operating income (loss)		25,830		(957)		—		24,873
Interest expense		(21,923)		—		—		(21,923)
Income (loss) before income tax expense		3,907		(957)		—		2,950
Income tax expense		(959)		—		—		(959)
Net income (loss)		2,948		(957)		—		1,991
Net loss attributable to noncontrolling interest		—		383		—		383
Net income (loss) attributable to Global Partners LP		2,948		(574)		—		2,374
Less: General partners' interest in net income, including incentive distribution rights		16		—		—		16
Limited partners' interest in net income (loss)	$	2,932	$	(574)	$	—	$	2,358

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Condensed Consolidating Statement of Operations

Three Months Ended June 30, 2016

(In thousands)


	(Issuer)		Non-
	Guarantor		Guarantor
	Subsidiaries		Subsidiary		Eliminations		Consolidated
Sales	$	2,145,425	$	1,067	$	(293)	$	2,146,199
Cost of sales		2,014,281		2,869		(293)		2,016,857
Gross profit		131,144		(1,802)		—		129,342
Costs and operating expenses:
Selling, general and administrative expenses		36,393		247		—		36,640
Operating expenses		74,857		1,034		—		75,891
Amortization expense		2,359		—		—		2,359
Net loss on sale and disposition of assets		375		—		—		375
Long-lived asset impairment		2,155		—		—		2,155
Total costs and operating expenses		116,139		1,281		—		117,420
Operating income (loss)		15,005		(3,083)		—		11,922
Interest expense		(21,015)		—		—		(21,015)
Loss before income tax benefit		(6,010)		(3,083)		—		(9,093)
Income tax benefit		550		—		—		550
Net loss		(5,460)		(3,083)		—		(8,543)
Net loss attributable to noncontrolling interest		—		1,233		—		1,233
Net loss attributable to Global Partners LP		(5,460)		(1,850)		—		(7,310)
Less: General partners' interest in net loss, including incentive distribution rights		(49)		—		—		(49)
Limited partners' interest in net loss	$	(5,411)	$	(1,850)	$	—	$	(7,261)

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Condensed Consolidating Statement of Operations

Six Months Ended June 30, 2017

(In thousands)


	(Issuer)		Non-
	Guarantor		Guarantor
	Subsidiaries		Subsidiary		Eliminations		Consolidated
Sales	$	4,358,998	$	1,603	$	(287)	$	4,360,314
Cost of sales		4,082,658		2,554		(287)		4,084,925
Gross profit		276,340		(951)		—		275,389
Costs and operating expenses:
Selling, general and administrative expenses		71,483		(17)		—		71,466
Operating expenses		137,492		890		—		138,382
Amortization expense		4,285		236		—		4,521
Net gain on sale and disposition of assets		(9,481)		—		—		(9,481)
Total costs and operating expenses		203,779		1,109		—		204,888
Operating income (loss)		72,561		(2,060)		—		70,501
Interest expense		(45,210)		—		—		(45,210)
Income (loss) before income tax expense		27,351		(2,060)		—		25,291
Income tax expense		(795)		—		—		(795)
Net income (loss) attributable to Global Partners LP		26,556		(2,060)		—		24,496
Net loss attributable to noncontrolling interest		—		824		—		824
Net income (loss) attributable to Global Partners LP		26,556		(1,236)		—		25,320
Less: General partners' interest in net income, including incentive distribution rights		170		—		—		170
Limited partners' interest in net income (loss)	$	26,386	$	(1,236)	$	—	$	25,150

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Condensed Consolidating Statement of Operations

Six Months Ended June 30, 2016

(In thousands)


	(Issuer)		Non-
	Guarantor		Guarantor
	Subsidiaries		Subsidiary		Eliminations		Consolidated
Sales	$	3,895,706	$	3,701	$	(2,396)	$	3,897,011
Cost of sales		3,634,297		5,709		(2,396)		3,637,610
Gross profit		261,409		(2,008)		—		259,401
Costs and operating expenses:
Selling, general and administrative expenses		71,144		480		—		71,624
Operating expenses		145,506		2,621		—		148,127
Amortization expense		4,868		—		—		4,868
Net loss on sale and disposition of assets		6,480		—		—		6,480
Long-lived asset impairment		2,155		—		—		2,155
Total costs and operating expenses		230,153		3,101		—		233,254
Operating income (loss)		31,256		(5,109)		—		26,147
Interest expense		(43,995)		—		—		(43,995)
Loss before income tax benefit		(12,739)		(5,109)		—		(17,848)
Income tax benefit		1,470		—		—		1,470
Net loss		(11,269)		(5,109)		—		(16,378)
Net loss attributable to noncontrolling interest		—		2,044		—		2,044
Net loss attributable to Global Partners LP		(11,269)		(3,065)		—		(14,334)
Less: General partners' interest in net loss, including incentive distribution rights		(96)		—		—		(96)
Limited partners' interest in net loss	$	(11,173)	$	(3,065)	$	—	$	(14,238)

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Condensed Consolidating Statement Cash Flows

Six Months Ended June 30, 2017

(In thousands)


	(Issuer)		Non-
	Guarantor		Guarantor
	Subsidiaries		Subsidiary		Consolidated
Cash flows from operating activities
Net cash provided by operating activities	$	209,298	$	629	$	209,927

Cash flows from investing activities
Capital expenditures		(19,308)		—		(19,308)
Proceeds from sale of property and equipment		28,218		20		28,238
Net cash provided by investing activities		8,910		20		8,930

Cash flows from financing activities
Net payments on working capital revolving credit facility		(175,500)		—		(175,500)
Net payments on revolving credit facility		(16,000)		—		(16,000)
Noncontrolling interest capital contribution		279		—		279
Distribution to noncontrolling interest		—		(465)		(465)
Distributions to partners		(31,277)		—		(31,277)
Net cash used in financing activities		(222,498)		(465)		(222,963)

Cash and cash equivalents
(Decrease) increase in cash and cash equivalents		(4,290)		184		(4,106)
Cash and cash equivalents at beginning of period		9,373		655		10,028
Cash and cash equivalents at end of period	$	5,083	$	839	$	5,922

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Condensed Consolidating Statement Cash Flows

Six Months Ended June 30, 2016

(In thousands)


	(Issuer)		Non-
	Guarantor		Guarantor
	Subsidiaries		Subsidiary		Consolidated
Cash flows from operating activities
Net cash used in (provided by) operating activities	$	(60,344)	$	361	$	(59,983)

Cash flows from investing activities
Capital expenditures		(38,846)		—		(38,846)
Proceeds from sale of property and equipment		11,673		9		11,682
Net cash used in (provided by) investing activities		(27,173)		9		(27,164)

Cash flows from financing activities
Net borrowings from working capital revolving credit facility		120,700		—		120,700
Net borrowings from revolving credit facility		(55,600)		—		(55,600)
Proceeds from sale-leaseback, net		62,476		—		62,476
Distribution to noncontrolling interest		2,697		(4,495)		(1,798)
Distributions to partners		(31,153)		—		(31,153)
Net cash provided by (used in) financing activities		99,120		(4,495)		94,625

Cash and cash equivalents
Increase (decrease) in cash and cash equivalents		11,603		(4,125)		7,478
Cash and cash equivalents at beginning of period		(3,574)		4,690		1,116
Cash and cash equivalents at end of period	$	8,029	$	565	$	8,594

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

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

Forward-Looking Statements

Some of the information contained in this Quarterly Report on Form 10-Q may contain forward-looking statements. Forward-looking statements include, without limitation, any statement that may project, indicate or imply future results, events, performance or achievements, and may contain the words “may,” “believe,” “should,” “could,” “expect,” “anticipate,” “plan,” “intend,” “estimate,” “continue,” “will likely result” or other similar expressions. In addition, any statement made by our management concerning future financial performance (including future revenues, earnings or growth rates), ongoing business strategies or prospects, and possible actions by us are also forward-looking statements. Forward-looking statements are not guarantees of performance. Although we believe these forward-looking statements are based on reasonable assumptions, statements made regarding future results are subject to a number of assumptions, uncertainties and risks, many of which are beyond our control, which may cause future results to be materially different from the results stated or implied in this document. These risks and uncertainties include, among other things:

We may not have sufficient cash from operations to enable us to 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 price or demand for the products we sell or a significant decrease in demand for our logistics activities could have an adverse effect on our financial condition, results of operations and cash available for distribution to our unitholders.

Our crude oil sales and logistics activities have been and could continue to be adversely affected by, among other things, changes in the crude oil market structure, grade differentials and volatility (or lack thereof), implementation of regulations that adversely impact the market for transporting crude oil or other products by rail, changes in refiner demand, severe weather conditions, significant changes in prices and interruptions in rail transportation services and other necessary services and equipment, such as railcars, trucks, loading equipment and qualified drivers.

We depend upon marine, pipeline, rail and truck transportation services for a substantial portion of our logistics business in transporting the products we sell. Implementation of regulations and directives that adversely impact the market for transporting these products by rail or otherwise could adversely affect that business. In addition, a disruption in these transportation services could have an adverse effect on our financial condition, results of operations and cash available for distribution to our unitholders.

We have contractual obligations for certain transportation assets such as railcars, barges and pipelines. A decline in demand for (i) the products we sell, including crude oil and ethanol, or (ii) our logistics activities, which has resulted and could continue to result in a decrease in the utilization of our transportation assets, could negatively impact our financial condition, results of operations and cash available for distribution to our unitholders. For example, during 2016, we experienced adverse market conditions in crude oil caused by an over-supplied crude oil market which resulted in tighter price differentials, and we experienced a reduction in our railcar movements but remained obligated to pay the applicable fixed charges for railcar leases.

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

We may not be able to fully implement or capitalize upon planned growth projects. Even if we consummate acquisitions or expend capital in pursuit of growth projects that we believe will be accretive, they may in fact result in no increase or even a decrease in cash available for distribution to our unitholders.

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Erosion of the value of major gasoline brands could adversely affect our gasoline sales and customer traffic.

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

Changes in 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 our home heating oil and residual oil sales.

Our risk management policies cannot eliminate all commodity risk, basis risk or the impact of unfavorable market conditions which can adversely affect our financial condition, results of operations and cash available for distribution to our unitholders. In addition, noncompliance with our risk management policies could result in significant financial losses.

Our results of operations are affected by the overall forward market for the products we sell, and pricing volatility may adversely impact our results.

Our business could be affected by a range of issues, such as changes in commodity prices, energy conservation, competition, the global economic climate, movement of products between foreign locales and within the United States, changes in refiner demand, weekly and monthly refinery output levels, changes in local, domestic and worldwide inventory levels, changes in safety regulations, failure to obtain renewal permits on favorable terms to us, seasonality, supply, weather and logistics disruptions and other factors and uncertainties inherent in the transportation, storage, terminalling and marketing of crude oil, refined products and renewable fuels.

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

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

The condition of credit markets may adversely affect our liquidity.

Our credit agreement and the indentures governing our senior notes contain operating and financial covenants, and our credit agreement contains borrowing base requirements. A failure to comply with the operating and financial covenants in our credit agreement, the indentures and any future financing agreements could impact our access to bank loans and other sources of financing as well as our ability to pursue our business activities.

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

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

Our business could expose us to litigation and result in an unfavorable outcome or settlement of one or more lawsuits where insurance proceeds are insufficient or otherwise unavailable.

Adverse developments in the areas where we conduct our business could have a material adverse effect on such businesses and can reduce our ability to make distributions to our unitholders.

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

We are exposed to performance risk in our supply chain.

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

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

Unitholders have limited voting rights and are not entitled to elect our general partner or its directors or 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, 2016 and Part II, Item 1A, “Risk Factors,” in this Quarterly Report on Form 10-Q.

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

Overview

General

We are a midstream logistics and marketing company engaged in the purchasing, selling, storing and logistics of transporting petroleum and related products, including gasoline and gasoline blendstocks (such as ethanol), distillates (such as home heating oil, diesel and kerosene), residual oil, renewable fuels, crude oil and propane. We own, control or have access to one of the largest terminal networks of refined petroleum products and renewable fuels in the Northeast. We are one of the largest distributors of gasoline, distillates, residual oil and renewable fuels to wholesalers, retailers and commercial customers in the New England states and New York. We are also one of the largest independent owners, suppliers and operators of gasoline stations and convenience stores in these areas. As of June 30, 2017, we had a portfolio of 1,443 owned, leased and/or supplied gasoline stations, including 239 directly operated convenience stores, in the Northeast, Maryland and Virginia. We also receive revenue from convenience store sales, rental income and sundries. In addition, we own transload and storage terminals in North Dakota and Oregon that extend our origin‑to‑destination capabilities from the mid‑continent region of the United States and Canada.

Collectively, we sold approximately $2.0 billion and $4.2 billion of refined petroleum products, renewable fuels, crude oil, propane and small amounts of natural gas for the three and six months ended June 30, 2017. In addition, we had other revenues of approximately $0.1 billion and $0.2 billion for the three and six months ended June 30, 2017, from convenience store sales at our directly operated stores, rental income from dealer leased and commissioned agent leased gasoline stations and from cobranding arrangements, and sundries.

We base our pricing on spot prices, fixed prices or indexed prices and routinely use the NYMEX, CME, ICE or other counterparties to hedge the risk inherent in buying and selling commodities. Through the use of regulated

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exchanges or derivatives, we seek to maintain a position that is substantially balanced between purchased volumes and sales volumes or future delivery obligations.

2017 Recent Events

Amended and Restated Credit Agreement—On April 25, 2017, we and certain of our subsidiaries entered into a third amended and restated credit agreement with aggregate commitments of $1.3 billion and a maturity date of April 30, 2020. See Note 7 of Notes to Consolidated Financial Statements for additional information.

Sale of Natural Gas and Electricity Business—On February 1, 2017, we completed the sale of our natural gas marketing and electricity brokerage businesses for a purchase price of approximately $17.3 million, subject to customary closing adjustments. Proceeds from the sale amounted to approximately $16.3 million, and we realized a gain on the sale of $14.2 million. The sale of our natural gas marketing and electricity brokerage businesses reflects our ongoing program to monetize non-strategic assets that are not fundamental to our growth strategy. Prior to the sale, the results of our natural gas marketing and electricity brokerage businesses were included in our Commercial segment.

2016 Events that Impacted Results

Early Termination of Railcar Sublease—On December 21, 2016 (effective December 31, 2016), we voluntarily terminated early a sublease with a counterparty for 1,610 railcars that were underutilized due to unfavorable market conditions in the crude oil by rail market. As a result of the sublease termination, we recognized one-time discounted lease exit and termination expenses of $80.7 million in the fourth quarter of 2016. The termination of the sublease eliminates future lease payments related to these railcars of approximately $30.0 million, $29.0 million and $13.0 million in 2017, 2018 and 2019, respectively.

Sale of Gasoline Stations—On August 22, 2016, Drake Petroleum Company, Inc., a subsidiary of ours, sold to Mirabito Holdings, Inc. 30 gasoline stations and convenience stores located in New York and Pennsylvania (the “Drake Sites”) for an aggregate total cash purchase price of approximately $40.0 million. In connection with closing, the parties entered into long-term supply contracts for branded and unbranded gasoline and other petroleum products.

Sale Leaseback Transaction—On June 29, 2016, we and our wholly owned subsidiaries Global Companies LLC, Global Montello Group Corp., Alliance Energy LLC and Bursaw Oil LLC sold to a premier institutional real estate investor (the “Buyer”) real property assets, including the buildings, improvements and appurtenances thereto, at 30 gasoline stations and convenience stores located in Connecticut, Maine, Massachusetts, New Hampshire and Rhode Island for a purchase price of approximately $63.5 million. In connection with the sale, we entered into a Master Unitary Lease Agreement with the Buyer to lease back the real property assets sold with respect to these sites. See Note 7 of Notes to Consolidated Financial Statements.

Expanded Retail Network—In April 2016, we expanded our gasoline station and convenience-store network in Western Massachusetts with the addition of 22 leased retail sites. Located in the Pittsfield and Springfield areas, these sites were added through long-term leases.

Operating Segments

We purchase refined petroleum products, renewable fuels, crude oil and propane primarily from domestic and foreign refiners and ethanol producers, crude oil producers, major and independent oil companies and trading companies. We operate our business under three segments: (i) Wholesale, (ii) GDSO and (iii) Commercial.

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Wholesale

In our Wholesale segment, we engage in the logistics of selling, gathering, storage and transportation of refined petroleum products, renewable fuels, crude oil and propane. We transport these products by railcars, barges and/or pipelines pursuant to spot or long-term contracts. From time to time, we aggregate crude oil by truck or pipeline in the mid-continent region of the United States and Canada, transport it by rail and ship it by barge to refiners. We sell home heating oil, branded and unbranded gasoline and gasoline blendstocks, diesel, kerosene, residual oil and propane to home heating oil and propane retailers and wholesale distributors. Generally, customers use their own vehicles or contract carriers to take delivery of the gasoline and distillates at bulk terminals and inland storage facilities that we own or control or at which we have throughput or exchange arrangements. Ethanol is shipped primarily by rail and by barge.

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

Gasoline Distribution and Station Operations

In our GDSO segment, gasoline distribution includes sales of branded and unbranded gasoline to gasoline station operators and sub-jobbers. Station operations include (i) convenience stores, (ii) rental income from gasoline stations leased to dealers, from commissioned agents and from cobranding arrangements and (iii) sundries (such as car wash sales, lottery and ATM commissions).

As of June 30, 2017, we had a portfolio of owned, leased and/or supplied gasoline stations, primarily in the Northeast, that consisted of the following:


Company operated		239
Commissioned agents		269
Lessee dealers		237
Contract dealers		698
Total		1,443

At our company‑operated stores, we operate the gasoline stations and convenience stores with our employees, and we set the retail price of gasoline at the station. At commissioned agent locations, we own the gasoline inventory, and we set the retail price of gasoline at the station and pay the commissioned agent a fee related to the gallons sold. We receive rental income from commissioned agent leased gasoline stations for the leasing of the convenience store premises, repair bays and other businesses that may be conducted by the commissioned agent. At dealer‑leased locations, the dealer purchases gasoline from us, and the dealer sets the retail price of gasoline at the dealer’s station. We also receive rental income from (i) dealer‑leased gasoline stations and (ii) cobranding arrangements. We also supply gasoline to locations owned and/or leased by independent contract dealers. Additionally, we have contractual relationships with distributors in certain New England states, pursuant to which we source and supply these distributors’ gasoline stations with ExxonMobil‑branded gasoline.

Commercial

In our Commercial segment, we include sales and deliveries to end user customers in the public sector and to large commercial and industrial end users of unbranded gasoline, home heating oil, diesel, kerosene, residual oil and bunker fuel. In the case of public sector commercial and industrial end user customers, we sell products primarily either through a competitive bidding process or through contracts of various terms. We generally arrange for the delivery of the product to the customer’s designated location, and we respond to publicly-issued requests for product proposals and quotes. Our Commercial segment also includes sales of custom blended fuels delivered by barges or from a terminal dock to ships through bunkering activity.

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Seasonality

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

Outlook

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

Our business is influenced by the overall markets for refined petroleum products, renewable fuels, crude oil and propane and increases and/or decreases in the prices of these products may adversely impact our financial condition, results of operations and cash available for distribution to our unitholders and the amount of borrowing available for working capital under our credit agreement. Results from our purchasing, storing, terminalling, transporting and selling operations are influenced by prices for refined petroleum products, renewable fuels, crude oil and propane, price volatility and the market for such products. Prices in the overall markets for these products may affect our financial condition, results of operations and cash available for distribution to our unitholders. Our margins can be significantly impacted by the forward product pricing curve, often referred to as the futures market. We typically hedge our exposure to petroleum product and renewable fuel price moves with futures contracts and, to a lesser extent, swaps. In markets where future prices are higher than current prices, referred to as contango, we may use our storage capacity to improve our margins by storing products we have purchased at lower prices in the current market for delivery to customers at higher prices in the future. In markets where future prices are lower than current prices, referred to as backwardation, inventories can depreciate in value and hedging costs are more expensive. For this reason, in these backward markets, we attempt to reduce our inventories in order to minimize these effects. When prices for the products we sell rise, some of our customers may have insufficient credit to purchase supply from us at their historical purchase volumes, and their customers, in turn, may adopt conservation measures which reduce consumption, thereby reducing demand for product. Furthermore, when prices increase rapidly and dramatically, we may be unable to promptly pass our additional costs on to our customers, resulting in lower margins which could adversely affect our results of operations. Higher prices for the products we sell may (1) diminish our access to trade credit support and/or cause it to become more expensive and (2) decrease the amount of borrowings available for working capital under our credit agreement as a result of total available commitments, borrowing base limitations and advance rates thereunder. When prices for the products we sell decline, our exposure to risk of loss in the event of nonperformance by our customers of our forward contracts may be increased as they and/or their customers may breach their contracts and purchase the products we sell at the then lower market price from a competitor. A significant decrease in the price for crude oil has adversely affected the economics of domestic crude oil production which, in turn, has had an adverse effect on our crude oil logistics activities and sales. A significant decrease in crude oil differentials has also had an adverse effect on our crude oil logistics activities and sales. In addition, the prolonged decline in crude oil prices and crude oil differentials has indicated an impairment of our long-lived assets at our terminals in North Dakota. As a result of these events, we recognized a goodwill and long-lived asset impairment of $149.9 million for year ended December 31, 2016.

We commit substantial resources to pursuing acquisitions and expending capital for growth projects, although there is no certainty that we will successfully complete any acquisitions or growth projects or receive the economic results we anticipate from completed acquisitions or growth projects. We are continuously engaged in discussions with potential sellers and lessors of existing (or suitable for development) terminalling, storage, logistics and/or marketing assets, including gasoline stations, and related businesses. Our growth largely depends

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on our ability to make accretive acquisitions and/or accretive development projects. We may be unable to execute such accretive transactions for a number of reasons, including the following: (1) we are unable to identify attractive transaction candidates or negotiate acceptable terms; (2) we are unable to obtain financing for such transactions on economically acceptable terms; or (3) we are outbid by competitors. In addition, we may consummate transactions that at the time of consummation we believe will be accretive but that ultimately may not be accretive. If any of these events were to occur, our future growth and ability to increase or maintain distributions could be limited. We can give no assurance that our transaction efforts will be successful or that any such efforts will be completed on terms that are favorable to us.

The condition of credit markets may adversely affect our liquidity. In the past, world financial markets experienced a severe reduction in the availability of credit. Possible negative impacts in the future could include a decrease in the availability of borrowings under our credit agreement, increased counterparty credit risk on our derivatives contracts and our contractual counterparties requiring us to provide collateral. In addition, we could experience a tightening of trade credit from our suppliers.

We depend upon marine, pipeline, rail and truck transportation services for a substantial portion of our logistics business in transporting the products we sell. A disruption in these transportation services could have an adverse effect on our financial condition, results of operations and cash available for distribution to our unitholders. Hurricanes, flooding and other severe weather conditions could cause a disruption in the transportation services we depend upon which could affect the flow of service. In addition, accidents, labor disputes between providers and their employees and labor renegotiations, including strikes, lockouts or a work stoppage, shortage of railcars, mechanical difficulties or bottlenecks and disruptions in transportation logistics could also disrupt our businesses. These events could result in service disruptions and increased cost which could also adversely affect our financial condition, results of operations and cash available for distribution to our unitholders. Other disruptions, such as those due to an act of terrorism or war, could also adversely affect our business.

We have contractual obligations for certain transportation assets such as railcars, barges and pipelines. A decline in demand for (i) the products we sell, including crude oil and ethanol, or (ii) our logistics activities, could result in a decrease in the utilization of our transportation assets, which could negatively impact our financial condition, results of operations and cash available for distribution to our unitholders. For example, during 2016, we experienced adverse market conditions in crude oil caused by an over-supplied crude oil market which resulted in tighter price differentials, and we experienced a reduction in our railcar movements but remained obligated to pay the applicable fixed charges for railcar leases.

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

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

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

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Energy efficiency, higher prices, new technology and alternative fuels could reduce demand for our products.

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. In addition, 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 regulations further promoting the use of cleaner fuels. End users who are dual-fuel users have the ability to switch between residual oil and natural gas. Other end users may elect to convert to natural gas. During a period of increasing residual oil prices relative to the prices of natural gas, dual-fuel customers may switch and other end users may convert to natural gas. During periods of increasing home heating oil prices relative to the price of natural gas, residential users of home heating oil may also convert to natural gas. Such switching or conversion could have an adverse effect on our financial condition, results of operations and cash available for distribution to our unitholders.

Changes in government usage mandates and tax credits could adversely affect the availability and pricing of ethanol, which could negatively impact our sales. The EPA has implemented a Renewable Fuels Standard (“RFS”) pursuant to the Energy Policy Act of 2005 and the Energy Independence and Security Act of 2007. The RFS program sets annual quotas for the quantity of renewable fuels (such as ethanol) that must be blended into transportation fuels consumed in the United States. A RIN is assigned to each gallon of renewable fuel produced in or imported into the United States. We are exposed to the volatility in the market price of RINs. We cannot predict the future prices of RINs. RIN prices are dependent upon a variety of factors, including EPA regulations, the availability of RINs for purchase, the price at which RINs can be purchased, and levels of transportation fuels produced, all of which can vary significantly from quarter to quarter. If sufficient RINs are unavailable for purchase or if we have to pay a significantly higher price for RINs, or if we are otherwise unable to meet the EPA’s RFS mandates, our results of operations and cash flows could be adversely affected. Future demand for ethanol will be largely dependent upon the economic incentives to blend based upon the relative value of gasoline and ethanol, taking into consideration the EPA’s regulations on RFS program and oxygenate blending requirements. A reduction or waiver of the RFS mandate or oxygenate blending requirements could adversely affect the availability and pricing of ethanol, which in turn could adversely affect our future gasoline and ethanol sales. In addition, changes in blending requirements could affect the price of RINs which could impact the magnitude of the mark-to-market liability recorded for the deficiency, if any, in our RIN position relative to our RVO at a point in time.

We may not be able to fully implement or capitalize upon planned growth projects. We could have a number of organic growth projects that may require the expenditure of significant amounts of capital in the aggregate. Many of these projects involve numerous regulatory, environmental, commercial and legal uncertainties beyond our control. As these projects are undertaken, required approvals, permits and licenses may not be obtained, may be delayed or may be obtained with conditions that materially alter the expected return associated with the underlying projects. Moreover, revenues associated with these organic growth projects would not increase immediately upon the expenditures of funds with respect to a particular project and these projects may be completed behind schedule or in excess of budgeted cost. We may pursue and complete projects in anticipation of market demand that dissipates or market growth that never materializes. As a result of these uncertainties, the anticipated benefits associated with our capital projects may not be achieved.

New, stricter environmental laws and other industry-related regulations or environmental litigation could significantly impact our operations and/or increase our costs, which could adversely affect our results of operations and financial condition. Our operations are subject to federal, state and local laws and regulations regulating, among other matters, logistics activities, product quality specifications and other environmental matters. The trend in environmental regulation has been towards more restrictions and limitations on activities that may affect the environment over time. Our business may be adversely affected by increased costs and liabilities resulting from such stricter laws and regulations. We try to anticipate future regulatory requirements that might be imposed and plan accordingly to remain in compliance with changing environmental laws and regulations and to minimize the costs of such compliance. Risks related to our environmental permits, including

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the risk of noncompliance, permit interpretation, permit modification, renewal of permits on less favorable terms, judicial or administrative challenges to permits by citizens groups or federal, state or local entities or permit revocation are inherent in the operation of our business, as it is with other companies engaged in similar businesses. We may not be able to renew the permits necessary for our operations, or we may be forced to accept terms in future permits that limit our operations or result in additional compliance costs. In recent years, the transport of crude oil and ethanol has become subject to additional regulation. The establishment of more stringent design or construction, or other requirements for railroad tank cars that are used to transport crude oil and ethanol with too short of a timeframe for compliance may lead to shortages of compliant railcars available to transport crude oil and ethanol, which could adversely affect our business. Likewise, in recent years, efforts have commenced to seek to use federal, state and local laws to contest issuance of permits, contest renewal of permits and restrict the types of railroad tanks cars that can be used to deliver crude oil and ethanol to bulk storage terminals. Were such laws to come into effect and were they to survive appeals and judicial review, they would potentially expose our operations to duplicative and possibly inconsistent regulation. There can be no assurances as to the timing and type of such changes in existing laws or the promulgation of new laws or the amount of any required expenditures associated therewith. Climate change continues to attract considerable public and scientific attention. In recent years environmental interest groups have filed suit against companies in the energy industry related to climate change. Should such suits succeed, we could face additional compliance costs or litigation risks.

Results of Operations

Evaluating Our Results of Operations

Our management uses a variety of financial and operational measurements to analyze our performance. These measurements include: (1) product margin, (2) gross profit, (3) earnings before interest, taxes, depreciation and amortization (“EBITDA”) and Adjusted EBITDA, (4) distributable cash flow, (5) selling, general and administrative expenses (“SG&A”), (6) operating expenses, and (7) degree day.

Product Margin

We view product margin as an important performance measure of the core profitability of our operations. We review product margin monthly for consistency and trend analysis. We define product margin as our product sales minus product costs. Product sales primarily include sales of unbranded and branded gasoline, distillates, residual oil, renewable fuels, crude oil, natural gas and propane, as well as convenience store sales, gasoline station rental income and revenue generated from our logistics activities when we engage in the storage, transloading and shipment of products owned by others. Product costs include the cost of acquiring the refined petroleum products, renewable fuels, crude oil, natural gas and propane and all associated costs including shipping and handling costs to bring such products to the point of sale as well as product costs related to convenience store items and costs associated with our logistics activities. We also look at product margin on a per unit basis (product margin divided by volume). Product margin is a non-GAAP financial measure used by management and external users of our consolidated financial statements to assess our business. Product margin should not be considered an alternative to net income, operating income, cash flow from operations or any other measure of financial performance presented in accordance with GAAP. In addition, our product margin may not be comparable to product margin or a similarly titled measure of other companies.

Gross Profit

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

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EBITDA and Adjusted EBITDA

EBITDA and Adjusted EBITDA are non-GAAP financial measures used as supplemental financial measures by management and may be used by external users of our consolidated financial statements, such as investors, commercial banks and research analysts, to assess:

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

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

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

our operating performance and return on invested capital as compared to those of other companies in the wholesale, marketing, storing and distribution of refined petroleum products, renewable fuels, crude oil, natural gas and propane, and in the gasoline stations and convenience stores business, 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.

Adjusted EBITDA is EBITDA further adjusted for gains or losses on the sale and disposition of assets and goodwill and long-lived asset impairment charges. EBITDA and Adjusted EBITDA should not be considered as alternatives 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 and Adjusted EBITDA exclude some, but not all, items that affect net income, and these measures may vary among other companies. Therefore, EBITDA and Adjusted 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 as defined by our partnership agreement is 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.

Distributable cash flow as used in our partnership agreement determines our ability to make cash distributions on our incentive distribution rights. The investment community also uses a distributable cash flow metric similar to the metric used in our partnership agreement with respect to publicly traded partnerships to indicate whether or not such partnerships have generated sufficient earnings on a current or historic level that can sustain or support an increase in quarterly cash distribution. Our partnership agreement does not permit adjustments for certain non-cash items, such as net losses on the sale and disposition of assets and goodwill and long-lived asset impairment charges.

Distributable cash flow should not be considered as an alternative to net income, operating income, cash flow from operations, or any other measure of financial performance presented in accordance with GAAP. In addition, our distributable cash flow may not be comparable to distributable cash flow or similarly titled measures of other companies.

Selling, General and Administrative Expenses

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

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Operating Expenses

Operating expenses are costs associated with the operation of the terminals, transload facilities and gasoline stations used in our business. Lease payments, maintenance and repair, property taxes, utilities, credit card fees, taxes, labor and labor-related expenses comprise the most significant portion of our operating expenses. The majority of these expenses remains 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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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):


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2017		2016		2017		2016
Net income (loss) attributable to Global Partners LP	$	2,374	$	(7,310)	$	25,320	$	(14,334)
EBITDA (1)	$	51,292	$	41,301	$	123,212	$	83,873
Adjusted EBITDA (1)	$	53,673	$	43,831	$	113,731	$	92,508
Distributable cash flow (2)(3)	$	21,789	$	14,248	$	65,963	$	30,629
Wholesale Segment:
Volume (gallons)		638,630		758,179		1,416,910		1,573,164
Sales
Gasoline and gasoline blendstocks	$	461,063	$	594,411	$	966,767	$	937,140
Crude oil (4)		143,143		160,595		246,671		309,097
Other oils and related products (5)		340,463		318,123		957,030		737,132
Total	$	944,669	$	1,073,129	$	2,170,468	$	1,983,369
Product margin
Gasoline and gasoline blendstocks	$	18,608	$	26,612	$	33,993	$	42,974
Crude oil (4)		4,761		(9,648)		11,653		(12,021)
Other oils and related products (5)		7,828		15,804		37,701		41,053
Total	$	31,197	$	32,768	$	83,347	$	72,006
Gasoline Distribution and Station Operations Segment:
Volume (gallons)		405,437		403,573		771,536		767,420
Sales
Gasoline	$	859,747	$	815,634	$	1,627,383	$	1,431,737
Station operations (6)		87,857		101,058		163,453		186,243
Total	$	947,604	$	916,692	$	1,790,836	$	1,617,980
Product margin
Gasoline	$	79,283	$	66,999	$	146,438	$	132,386
Station operations (6)		43,242		49,267		82,137		92,192
Total	$	122,525	$	116,266	$	228,575	$	224,578
Commercial Segment:
Volume (gallons)		130,942		115,275		262,465		243,000
Sales	$	197,257	$	156,378	$	399,010	$	295,662
Product margin	$	4,124	$	5,480	$	8,313	$	12,390
Combined sales and product margin:
Sales	$	2,089,530	$	2,146,199	$	4,360,314	$	3,897,011
Product margin (7)	$	157,846	$	154,514	$	320,235	$	308,974
Depreciation allocated to cost of sales		(22,484)		(25,172)		(44,846)		(49,573)
Combined gross profit	$	135,362	$	129,342	$	275,389	$	259,401

GDSO portfolio as of June 30, 2017 and 2016:		2017		2016
Company operated		239		290
Commissioned agents		269		291
Lessee dealers		237		265
Contract dealers		698		665
Total GDSO portfolio		1,443		1,511

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	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2017			2016			2017			2016
Weather conditions:
Normal heating degree days		784			784			3,654			3,685
Actual heating degree days		767			786			3,426			3,346
Variance from normal heating degree days		(2)	%		0.3	%		(6)	%		(9)	%
Variance from prior period actual heating degree days		(2)	%		7	%		2	%		(20)	%

(1)

EBITDA and Adjusted EBITDA are non-GAAP financial measures which are discussed above under “—Evaluating Our Results of Operations.” The table below presents reconciliations of EBITDA and Adjusted EBITDA to the most directly comparable GAAP financial measures.

(2)

Distributable cash flow is a non-GAAP financial measure which is discussed above under “—Evaluating Our Results of Operations.” As defined by our partnership agreement, distributable cash flow is not adjusted for certain non-cash items, such as net losses on the sale and disposition of assets and goodwill and long-lived asset impairment charges. The table below presents reconciliations of distributable cash flow to the most directly comparable GAAP financial measures.

(3)

Distributable cash flow includes a net loss on sale and disposition of assets of $2.4 million and $0.4 million for the three months ended June 30, 2017 and 2016, respectively, and $4.7 million and $6.5 million for the six months ended June 30, 2017 and 2016, respectively. For the three and six months ended June 30, 2016, distributable cash flow also includes a long-lived asset impairment of $2.2 million. Excluding these charges, distributable cash flow would have been $24.2 million and $16.8 million for the three months ended June 30, 2017 and 2016, respectively, and $70.7 million and $39.3 million for the six months ended June 30, 2017 and 2016, respectively. For the six months ended June 30, 2017, distributable cash flow also includes a $14.2 million gain on the sale of our natural gas marketing and electricity brokerage business in February 2017. See Note 1 of Notes to Consolidated Financial Statements.

(4)

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

(5)

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

(6)

Station operations consist of convenience stores sales, rental income and sundries.

(7)

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

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


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2017		2016		2017		2016
Reconciliation of net income (loss) to EBITDA and Adjusted EBITDA:
Net income (loss)	$	1,991	$	(8,543)	$	24,496	$	(16,378)
Net loss attributable to noncontrolling interest		383		1,233		824		2,044
Net income (loss) attributable to Global Partners LP		2,374		(7,310)		25,320		(14,334)
Depreciation and amortization, excluding the impact of noncontrolling interest		26,036		28,146		51,887		55,682
Interest expense, excluding the impact of noncontrolling interest		21,923		21,015		45,210		43,995
Income tax expense (benefit)		959		(550)		795		(1,470)
EBITDA		51,292		41,301		123,212		83,873
Net loss (gain) on sale and disposition of assets		2,381		375		(9,481)		6,480
Long-lived asset impairment		—		2,155		—		2,155
Adjusted EBITDA	$	53,673	$	43,831	$	113,731	$	92,508

Reconciliation of net cash provided by (used in) operating activities to EBITDA and Adjusted EBITDA:
Net cash provided by (used in) operating activities	$	92,362	$	(6,467)	$	209,927	$	(59,983)
Net changes in operating assets and liabilities and certain non-cash items		(63,822)		27,204		(132,518)		101,554
Net cash from operating activities and changes in operating assets and liabilities attributable to noncontrolling interest		(130)		99		(202)		(223)
Interest expense, excluding the impact of noncontrolling interest		21,923		21,015		45,210		43,995
Income tax expense (benefit)		959		(550)		795		(1,470)
EBITDA		51,292		41,301		123,212		83,873
Net loss (gain) on sale and disposition of assets		2,381		375		(9,481)		6,480
Long-lived asset impairment		—		2,155		—		2,155
Adjusted EBITDA	$	53,673	$	43,831	$	113,731	$	92,508

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


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2017		2016		2017		2016
Reconciliation of net income (loss) to distributable cash flow:
Net income (loss)	$	1,991	$	(8,543)	$	24,496	$	(16,378)
Net loss attributable to noncontrolling interest		383		1,233		824		2,044
Net income (loss) attributable to Global Partners LP		2,374		(7,310)		25,320		(14,334)
Depreciation and amortization, excluding the impact of noncontrolling interest		26,036		28,146		51,887		55,682
Amortization of deferred financing fees and senior notes discount		1,780		1,866		3,671		3,638
Amortization of routine bank refinancing fees		(1,063)		(1,168)		(2,230)		(2,245)
Maintenance capital expenditures, excluding the impact of noncontrolling interest		(7,338)		(7,286)		(12,685)		(12,112)
Distributable cash flow (1)(2)	$	21,789	$	14,248	$	65,963	$	30,629

Reconciliation of net cash provided by (used in) operating activities to distributable cash flow:
Net cash provided by (used in) operating activities	$	92,362	$	(6,467)	$	209,927	$	(59,983)
Net changes in operating assets and liabilities and certain non-cash items		(63,822)		27,204		(132,518)		101,554
Net cash from operating activities and changes in operating assets and liabilities attributable to noncontrolling interest		(130)		99		(202)		(223)
Amortization of deferred financing fees and senior notes discount		1,780		1,866		3,671		3,638
Amortization of routine bank refinancing fees		(1,063)		(1,168)		(2,230)		(2,245)
Maintenance capital expenditures, excluding the impact of noncontrolling interest		(7,338)		(7,286)		(12,685)		(12,112)
Distributable cash flow (1)(2)	$	21,789	$	14,248	$	65,963	$	30,629

(1)

Distributable cash flow is a non-GAAP financial measure which is discussed above under “—Evaluating Our Results of Operations.” As defined by our partnership agreement, distributable cash flow is not adjusted for certain non-cash items, such as net losses on the sale and disposition of assets and goodwill and long-lived asset impairment charges. The table above presents reconciliations of distributable cash flow to the most directly comparable GAAP financial measures.

(2)

Consolidated Sales

Our total sales were $2.1 billion for each of the three months ended June 30, 2017 and 2016. Our aggregate volume of product sold was 1.2 billion gallons and 1.3 billion gallons for the three months ended June 30, 2017 and 2016, respectively, a decrease of 0.1 billion gallons. The decrease in volume sold includes a decrease of 120 million gallons in our Wholesale segment, primarily in gasoline and gasoline blendstocks and crude oil. The decrease in volume sold was offset by increases of 16 million gallons in our Commercial segment and 2 million gallons in our GDSO segment.

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Our total sales were $4.4 billion and $3.9 billion for the six months ended June 30, 2017 and 2016, respectively, an increase of $0.5 billion, or 12%, due to an increase in prices, partially offset by a decline in volume sold, largely in crude oil in our Wholesale segment. Our aggregate volume of product sold was 2.5 billion gallons and 2.6 billion gallons for the six months ended June 30, 2017 and 2016, respectively, a decrease of 0.1 billion gallons. The decrease in volume sold includes a decrease of 156 million gallons in our Wholesale segment, primarily in crude oil but also in gasoline and gasoline blendstocks. The decrease in volume sold was offset by increases of 19 million gallons in our Commercial segment and 4 million gallons in our GDSO segment.

Gross Profit

Our gross profit was $135.4 million and $129.3 million for three months ended June 30, 2017 and 2016, respectively, an increase of $6.1 million, or 5%, primarily due to improved product margins in crude oil in our Wholesale segment and in gasoline distribution in our GDSO segment, partially offset by decreases in product margins in gasoline and gasoline blendstocks and other oils and related products in our Wholesale segment and in station operations in our GDSO segment.

Our gross profit was $275.4 million and $259.4 million and for the six months ended June 30, 2017 and 2016, respectively, an increase of $16.0 million, or 6%, primarily due to improved product margins in crude oil in our Wholesale segment and in gasoline distribution in our GDSO segment, partially offset by decreases in product margins in gasoline and gasoline blendstocks and other oils and related products in our Wholesale segment, in station operations in our GDSO segment and in natural gas in our Commercial segment.

Results for Wholesale Segment

Gasoline and Gasoline Blendstocks. Sales from wholesale gasoline and gasoline blendstocks were $0.5 billion and $0.6 billion for the three months ended June 30, 2017 and 2016, respectively, a decrease of $0.1 billion, or 22%, primarily due to a decrease in volume sold, largely in gasoline blendstocks. Our gasoline and gasoline blendstocks product margin was $18.6 million and $26.6 million for the three months ended June 30, 2017 and 2016, respectively, a decrease of $8.0 million, or 30%, primarily due to less favorable market conditions in gasoline.

Sales from wholesale gasoline and gasoline blendstocks were $0.9 billion for each of the six months ended June 30, 2017 and 2016, increasing $29.6 million, or 3.2%, due to an increase in prices. Our gasoline and gasoline blendstocks product margin was $34.0 million and $43.0 million for the six months ended June 30, 2017 and 2016, a decrease of $9.0 million, or 21%, primarily due to less favorable market conditions in gasoline in the second quarter of 2017 and to less favorable market conditions in gasoline blendstocks, primarily ethanol, in the first quarter of 2017.

Crude Oil. Crude oil sales and logistics revenues were $0.1 billion and $0.2 billion for the three months ended June 30, 2017 and 2016, respectively, with a decrease of approximately $17.4 million for the second quarter of 2017 due to a decline in volume sold as the crude oil by rail market to the East Coast continued to be negatively impacted by competitive imports. Our crude oil product margin was $4.8 million and negative $9.6 million for the three months ended June 30, 2017 and 2016, respectively, an increase of $14.4 million. The increase was primarily due to $10.7 million in revenue related to a take-or-pay contract with one particular customer and an $8.1 million decrease in railcar lease expense as a result of our early termination of a sublease in December 2016, partially offset by less volume through our system. Our product margin for the second quarter of 2016 was negatively impacted by the absence of logistics nominations from one particular contract customer.

Crude oil sales and logistics revenues were $0.2 billion and $0.3 billion for the six months ended June 30, 2017 and 2016, respectively, a decrease of $0.1 billion, or 20%, due to a decline in volume sold. Our crude oil product margin was $11.6 million and negative $12.0 million for the six months ended June 30, 2017 and 2016, respectively, an increase of $23.6 million. The increase was primarily due to $21.4 million in revenue related to a take-or-pay contract with one particular customer and a $16.6 million in decrease in railcar lease expense as a result of our early termination of a sublease in December 2016, partially offset by less volume through our system. Our product margin for the first six months of 2016 was negatively impacted by minimal logistics nominations from one particular contract customer.

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Other Oils and Related Products. Sales from other oils and related products (primarily distillates, residual oil and propane) were $0.3 billion for each of the three months ended June 30, 2017 and 2016. Our product margin from other oils and related products was $7.8 million and $15.8 million for the three months ended June 30, 2017 and 2016, respectively, a decrease of $8.0 million, or 51%, primarily due to less favorable market conditions.

Sales from other oils and related products were $0.9 billion and $0.7 billion for the six months ended June 30, 2017 and 2016, respectively, an increase of $0.2 billion, or 29%, primarily due to an increase in prices in the first quarter of 2017. Our product margin from other oils and related products was $37.7 million and $41.0 million for the six months ended June 30, 2017 and 2016, respectively, a decrease of $3.3 million, or 8%, primarily due to less favorable market conditions in the second quarter of 2017, partially offset by favorable market conditions in distillates in the first quarter of 2017. While weather was colder for the first quarter of 2017 compared to the first quarter of 2016, our product margin in other oils and related products was negatively impacted by warmer-than-normal temperatures in each of the first quarters of 2017 and 2016.

Results for Gasoline Distribution and Station Operations Segment

Gasoline Distribution. Sales from gasoline distribution were $0.8 billion for each of the three months ended June 30, 2017 and 2016, increasing $44.1 million, or 5%. Our product margin from gasoline distribution was $79.3 million and $67.0 million for the three months ended June 30, 2017 and 2016, respectively, an increase of $12.3 million, or 18%, in part due to declining wholesale gasoline prices during the second quarter of 2017 compared to rising wholesale gasoline prices during the second quarter of 2016, particularly during April and May.

Sales from gasoline distribution were $1.6 billion and $1.4 billion for the six months ended June 30, 2017 and 2016, respectively, an increase of $0.2 billion, or 14%, primarily due to higher wholesale gasoline prices. Our product margin from gasoline distribution was $146.4 million and $132.4 million for the six months ended June 30, 2017 and 2016, respectively, an increase of $14.0 million, or 11%, in part due to declining wholesale gasoline prices during the second quarter of 2017. For the first six months of 2017, our product margin in gasoline distribution reflects the sale of sites, including the Drake Sites sold in August 2016, and was negatively impacted by rising wholesale gasoline prices in the first quarter of 2017. For the first six months of 2016, our product margin in gasoline distribution was negatively impacted by rising wholesale gasoline prices.

Station Operations. Our station operations, which include (i) convenience stores sales at our directly operated stores, (ii) rental income from gasoline stations leased to dealers or from commissioned agents and from cobranding arrangements and (iii) sale of sundries, such as car wash sales, lottery and ATM commissions, collectively generated revenues of $0.1 billion for each of the three months ended June 30, 2017 and 2016. Our product margin from station operations was $43.2 million and $49.3 million for the three months ended June 30, 2017 and 2016, respectively, a decrease of $6.1 million, or 12%, largely due to the sale of sites, including the Drake Sites sold in August 2016.

Sales from our station operations were approximately $0.2 billion for each of the six months ended June 30, 2017 and 2016. Our product margin from station operations was $82.1 million and $92.2 million for the six months ended June 30, 2017 and 2016, respectively, a decrease of $10.1 million, or 11%, primarily due to the sale of sites, including the Drake Sites sold in August 2016, partially offset by the addition of leased company operated sites in April 2016.

Results for Commercial Segment

Our commercial sales were $0.2 billion for each of the three months ended June 30, 2017 and 2016. Our commercial product margin was $4.1 million and $5.5 million for the three months ended June 30, 2017 and 2016, respectively, a decrease of $1.4 million, or 25%, primarily due to the sale of our natural gas marketing and electricity brokerage businesses in February 2017, which also negatively impacted our sales.

Our commercial sales were $0.4 billion and $0.3 billion for the six months ended June 30, 2017 and 2016, respectively, an increase of $0.1 billion, or 33%, primarily due to higher prices in the first quarter of 2017. Our commercial product margin was $8.3 million and $12.4 million for the six months ended June 30, 2017 and 2016,

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respectively, a decrease of $4.1 million, or 33%, primarily due to the sale of our natural gas marketing and electricity brokerage businesses in February 2017, which also negatively impacted our sales.

Selling, General and Administrative Expenses

SG&A expenses were $34.7 million and $36.6 million for the three months ended June 30, 2017 and 2016, respectively, a decrease of $1.9 million, or 5%, including decreases of $1.3 million in professional fees, $1.1 million in wages and benefits and $1.3 million in various SG&A expenses, as well as a decline of $0.8 million in severance charges incurred in the second quarter of 2016 related to a reduction in our workforce. The decrease in SG&A expenses was offset by an increase of $1.8 million in accrued incentive compensation. In addition, during the second quarter of 2017, we incurred $0.8 million for certain costs in connection with a compensation funding agreement with our general partner (see Note 12 of Notes to Consolidated Financial Statements).

SG&A expenses were $71.5 million and $71.6 million for the six months ended June 30, 2017 and 2016, respectively, a decrease of $0.1 million, including decreases of $0.9 million in wages and benefits, $0.8 million in professional fees and $0.6 million in various SG&A expenses, as well as a decline of $2.1 million in severance charges incurred in the first six months of 2016 related to a reduction in our workforce. The decrease in SG&A expenses was offset by an increase of $3.5 million in accrued incentive compensation. In addition, during the second quarter of 2017, we incurred $0.8 million for certain costs in connection with a compensation funding agreement with our general partner (see Note 12 of Notes to Consolidated Financial Statements).

Operating Expenses

Operating expenses were $71.2 million and $75.9 million for the three months ended June 30, 2017 and 2016, respectively, a decrease of $4.7 million, or 6%. Operating expenses decreased by $3.5 million associated with our GDSO operations due, in part, to the sale of sites, including the Drake Sites sold in August 2016, and by $0.7 million at our Basin Transload facilities in North Dakota due to less activity. In addition, in the second quarter of 2016, we incurred $2.2 million in costs associated with cleaning tanks and related infrastructure at our Oregon facility in order to convert the facility to ethanol transloading. The decrease in operating expenses was offset by an increase of $1.7 million associated with our terminal operations, in part due to an increase in maintenance and repairs.

Operating expenses were $138.4 million and $148.1 million for the six months ended June 30, 2017 and 2016, respectively, a decrease of $9.7 million, or 7%. Operating expenses decreased by $5.8 million associated with our GDSO operations due, in part, to the sale of sites, including the Drake Sites sold in August 2016, offset by increases in credit card fees due to higher wholesale gasoline prices and in rent expense associated with additional leased sites. Operating expenses also decreased by $1.7 million at our Basin Transload facilities in North Dakota due to less activity. In addition, for the first six months of 2016, we incurred $3.8 million in costs associated with cleaning tanks and related infrastructure at our Oregon facility in order to convert the facility to ethanol transloading. The decrease in operating expenses was offset by an increase of $1.6 million associated with our terminal operations, in part due to an increase in maintenance and repairs.

Amortization Expense

Amortization expense related to our intangible assets was $2.2 million and $2.4 million for the three months ended June 30, 2017 and 2016, respectively, and $4.5 million and $4.9 million for the six months ended June 30, 2017 and 2016, respectively.

Net (Loss) Gain on Sale and Disposition of Assets

Net (loss) gain on sale and disposition of assets was ($2.4 million) and ($0.4 million) for three months ended June 30, 2017 and 2016, respectively, primarily due to the sale of GDSO sites. Net gain (loss) on sale and disposition of assets was $9.5 million and ($6.5 million) for the six months ended June 30, 2017 and 2016, respectively. For the six months ended June 30, 2017, we recorded a $14.2 million gain associated with the sale of our natural gas marketing and electricity brokerage businesses in February 2017 and a net loss on the sale and disposition of assets of ($4.7 million).

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The net losses for the six months ended June 30, 2017 and 2016 were primarily due to the sale of GDSO sites. See Note 6 of Notes to Consolidated Financial Statements for additional information.

Long-Lived Asset Impairment

For the three and six months ended June 30, 2017, we did not record any long-lived asset impairment charges. For the three and six months ended June 30, 2016, we recorded long-lived asset impairment charges of $2.2 million, consisting of $1.9 million related to assets used in supplying compressed natural gas and $0.3 million related to assets of one discrete GDSO site.

Interest Expense

Interest expense was $21.9 million and $21.0 million for the three months ended June 30, 2017 and 2016, respectively, an increase of $0.9 million, or 4%, primarily due to $1.1 million associated with the financing obligation recognized in connection with the Sale Leaseback Transaction entered into in June 2016 and a $0.6 million write-off of a portion of our deferred financing fees associated with the amendment and restatement of our credit agreement in April 2017. The increase in interest expense was partially offset by lower average balances on our credit facilities for the second quarter of 2017.

Interest expense was $45.2 million and $44.0 million for the six months ended June 30, 2017 and 2016, respectively, an increase of $1.2 million, or 3%, primarily due to $2.2 million associated with the financing obligation recognized in connection with the Sale Leaseback Transaction entered into in June 2016 and a $0.6 million write-off of a portion of our deferred financing fees associated with the amendment of our credit agreement in April 2017. The increase in interest expense was partially offset by a $1.8 million write-off of a portion of our deferred financing fees in February 2016 associated the reduction of our working capital revolving credit facility under our prior credit agreement and by lower average balances on our revolving credit facility and lower average interest rates due to the May 2016 expiration of our interest rate swap.

Please see Note 7 of Notes to Consolidated Financial Statements for additional information on the Sale Leaseback Transaction and the write-offs of deferred financing fees.

Income Tax (Expense) Benefit

Income tax (expense) benefit of ($0.9 million) and $0.6 million for the three months ended June 30, 2017 and 2016, respectively, and ($0.8 million) and $1.5 million for the six months ended June 30, 2017 and 2016, respectively, reflect income tax expense on the operating results of GMG, which is a taxable entity for federal and state income tax purposes.

Net Loss Attributable to Noncontrolling Interest

In February 2013, we acquired a 60% membership interest in Basin Transload. The net loss attributable to noncontrolling interest was $0.4 million and $1.2 million for the three months ended June 30, 2017 and 2016, respectively, and $0.8 million and $2.0 million for the six months ended June 30, 2017 and 2016, respectively, which represents the 40% noncontrolling ownership of the net loss reported.

Liquidity and Capital Resources

Liquidity

Our primary liquidity needs are to fund our working capital requirements, capital expenditures and distributions and to service our indebtedness. Our primary sources of liquidity are cash generated from operations, amounts available under our working capital revolving credit facility and equity and debt offerings. Please read “—Credit Agreement” for more information on our working capital revolving credit facility.

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Working capital was $269.8 million and $276.2 million at June 30, 2017 and December 31, 2016, respectively, a decrease of $6.4 million. The decreases to working capital were primarily due to decreases of $160.4 million in accounts receivable and $151.5 million in inventories due to seasonality relating to the heating season, reduced inventory volume and a decline in prices, for a total decrease of $311.9 million. The increases to working capital primarily include (i) a $175.5 million decrease in the current portion of our working capital revolving credit facility, which represents the amount we expect to pay down during the course of the year (see Note 7 of Notes to Consolidated Financial Statements); (ii) a $124.5 million reduction in accounts payable, primarily due to seasonality relating to the heating season and to a decline in prices; and (iii) a $16.1 million decrease in accrued expenses and other current liabilities, for a total increase of $316.1 million.

Cash Distributions

During 2017, we paid the following cash distributions to our common unitholders and our general partner:


			Distribution Paid for the
Cash Distribution Payment Date	Total Paid		Quarterly Period Ended
February 14, 2017	$	15.8 million	Fourth quarter 2016
May 15, 2017	$	15.8 million	First quarter 2017

On July 28, 2017, the board of directors of our general partner declared a quarterly cash distribution of $0.4625 per unit ($1.85 per unit on an annualized basis) for the period from April 1, 2017 through June 30, 2017 to our unitholders of record as of the close of business on August 9, 2017. We expect to pay the cash distribution of approximately $15.8 million on August 14, 2017.

Contractual Obligations

We have contractual obligations that are required to be settled in cash. The amounts of our contractual obligations at June 30, 2017 were as follows (in thousands):


	Payments due by period
	Remainder of								2021 and
Contractual Obligations	2017		2018		2019		2020		Thereafter		Total
Credit facility obligations (1)	$	107,003	$	155,581	$	155,581	$	50,687	$	—	$	468,852
Senior notes obligations (2)		33,328		44,438		44,438		44,438		762,657		929,299
Operating lease obligations (3)		58,756		90,954		58,456		35,119		173,245		416,530
Capital lease obligations		204		6		—		—		—		210
Other long-term liabilities (4)		14,624		24,633		37,791		25,150		76,323		178,521
Financing obligations (5)		7,123		14,409		14,643		14,882		144,565		195,622
Total	$	221,038	$	330,021	$	310,909	$	170,276	$	1,156,790	$	2,189,034

(1)

Includes principal and interest on our working capital revolving credit facility and our revolving credit facility at June 30, 2017 and assumes a ratable payment through the expiration date. Our credit agreement has a contractual maturity of April 30, 2020 and no principal payments were required prior to that maturity date. However, we repay amounts outstanding and reborrow funds based on our working capital requirements. Therefore, the current portion of the working capital revolving credit facility included in the accompanying balance sheets is the amount we expected to pay down during the course of the year, and the long-term portion of the working capital revolving credit facility is the amount we expected to be outstanding during the entire year. Please read “—Credit Agreement” for more information on our working capital revolving credit facility.

(2)

Includes principal and interest on our senior notes. No principal payments are required prior to maturity.

(3)

Includes operating lease obligations related to leases for office space and computer equipment, land, terminals and throughputs, gasoline stations, railcars, mobile equipment, access rights and barges.

(4)

Includes amounts related to our 15-year brand fee agreement entered into in 2010 with ExxonMobil and amounts related to our pipeline connection agreements and our natural gas transportation and reservation agreements. Other long-term liabilities include pension and deferred compensation obligations.

(5)

Includes lease rental payments in connection with (i) the acquisition of Capitol related to properties previously sold by Capitol within two sale-leaseback transactions; and (ii) the sale of real property assets at 30 gasoline stations and convenience stores. These transactions did not meet the criteria for sale accounting and the lease rental payments are classified as interest expense on

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the respective financing obligation and the pay-down of the related financing obligation. See Note 7 of Notes to Consolidated Financial Statement for additional information.

Capital Expenditures

Our operations require investments to maintain, expand, upgrade and enhance existing operations and to meet environmental and operational 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 also include expenditures required to maintain equipment reliability, tank 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 $12.7 million and $12.1 million in maintenance capital expenditures for the six months ended June 30, 2017 and 2016, respectively, which are included in capital expenditures in the accompanying consolidated statements of cash flows, of which approximately $9.8 million and $8.7 million for the six months ended June 30, 2017 and 2016, respectively, are related to our investments in our gasoline stations. 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, for example, increasing dock capacity and tankage, diversifying product availability, investing in raze and rebuilds and new-to-industry gasoline stations and convenience stores, increasing storage flexibility at various terminals and by adding terminals to our storage network. We have the ability to fund our expansion capital expenditures through cash from operations or our credit agreement or by issuing debt securities or additional equity. We had approximately $6.6 million and $26.7 million in expansion capital expenditures for the six months ended June 30, 2017 and 2016, respectively, which are included in capital expenditures in the accompanying consolidated statements of cash flows.

For the six months ended June 30, 2017, the $6.6 million in expansion capital expenditures primarily related to investments in information technology and related equipment and, to a lesser extent, raze and rebuilds and improvements at retail gasoline stations.

For the six months ended June 30, 2016, the $26.7 million in expansion capital expenditures consisted of (i) $15.6 million in raze and rebuilds, expansion and improvements at retail gasoline stations and new-to-industry sites, (ii) $9.0 million in costs associated with our terminal assets, including dock expansion at our Oregon facility and tank construction projects, and (iii) $2.1 million in other expansion capital expenditures including, in part, investments in information technology and computer and equipment.

We currently expect maintenance capital expenditures of approximately $35.0 million to $45.0 million and expansion capital expenditures of approximately $25.0 million to $35.0 million in 2017, relating primarily to investments in our gasoline station business. These current estimates depend, in part, on the timing of completion of projects, availability of equipment, weather and unanticipated events or opportunities requiring additional maintenance or investments.

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 have an adverse effect on our borrowing capacity as well as our ability to issue additional common units and/or debt securities.

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Cash Flow

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


	Six Months Ended
	June 30,
	2017		2016
Net cash provided by (used in) operating activities	$	209,927	$	(59,983)
Net cash provided by (used in) investing activities	$	8,930	$	(27,164)
Net cash (used in) provided by financing activities	$	(222,963)	$	94,625

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

Net cash provided by (used in) operating activities was $209.9 million and ($60.0 million) for the six months ended June 30, 2017 and 2016, respectively, for a period-over-period increase in cash provided by operating activities of $269.9 million. The primary drivers of the change include the following (in thousands):


	Six Months Ended				Period over
	June 30,				Period
	2017		2016		Change
Decrease (increase) in accounts receivable	$	159,599	$	(46,838)	$	206,437
Decrease (increase) in inventories	$	150,762	$	(55,042)	$	205,804
Decrease in accounts payable	$	(124,527)	$	(16,974)	$	(107,553)
(Decrease) increase in change in derivatives	$	(9,540)	$	28,686	$	(38,226)

During the six months ended June 30, 2017, the decreases in accounts receivable, inventories and accounts payable were primarily due to the change in activity as we exited the heating season, reduced inventory volume and a decline in prices. The increase in net cash provided by operating activities also reflects the period-over-period increase in net income of $40.9 million, offset by the change in derivatives year over year which required funds of $38.2 million.

During the six months ended June 30, 2016, the increases in inventories and accounts receivable were largely due to higher prices, and the decrease in accounts payable was primarily due to the change in activity as we exited the heating season and because of lower crude oil volume sold.

Net cash provided by investing activities was $8.9 million for the six months ended June 30, 2017 and included $28.2 million in proceeds from the sale of property and equipment ($16.3 million from the sale of our natural gas marketing and electricity brokerage businesses, less $0.5 million in related transaction costs, and $12.4 million primarily from the sales of GDSO sites), offset by $12.7 million in maintenance capital expenditures and $6.6 million in expansion capital expenditures.

Net cash used in investing activities was $27.1 million for the six months ended June 30, 2016 and included $26.7 million in expansion capital expenditures and $12.1 million in maintenance capital expenditures, offset by $11.7 million in proceeds from the sale of property and equipment.

See “—Capital Expenditures” for a discussion of our expansion capital expenditures for the six months ended June 30, 2017 and 2016.

Net cash used in financing activities was $223.0 million for the six months ended June 30, 2017 and included $175.5 million in net payments on our working capital revolving credit facility, $31.3 million in cash distributions to our common unitholders and our general partner, $16.0 million in net payments on our revolving credit facility and $0.5 million in distributions to our noncontrolling interest at Basin Transload, offset by $0.3 million in capital contributions from our noncontrolling interest at Basin Transload.

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Net cash provided by financing activities was $94.6 million for the six months ended June 30, 2016 and included $120.7 million in net borrowings from our working capital revolving credit facility and $62.5 million in net proceeds from the Sale Leaseback Transaction (see Note 7 to Notes to Consolidated Financial Statements), offset by $55.6 million in net payments on our revolving credit facility, $31.2 million in cash distributions to our common unitholders and our general partner and $1.8 million in distributions to our noncontrolling interest at Basin Transload.

Credit Agreement

On April 25, 2017, we, our operating company, our operating subsidiaries and GLP Finance Corp., as borrowers, entered into a third amended and restated credit agreement, with aggregate commitments available in the amount of $1.3 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 matures on April 30, 2020.

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 our borrowing base and $850.0 million; and

a $450.0 million revolving credit facility to be used for acquisitions, joint ventures, capital expenditures, letters of credit and general corporate purposes.

In addition, the credit agreement has an accordion feature whereby we may request on the same terms and conditions then applicable to the credit agreement, provided no Event of Default (as defined in the credit agreement) then exists, an increase to the working capital revolving credit facility, the revolving credit facility, or both, by up to another $300.0 million, in the aggregate, for a total credit facility of up to $1.6 billion. Any such request for an increase must be in a minimum amount of $25.0 million. We cannot provide assurance, however, that our lending group will agree to fund any request by us for additional amounts in excess of the total available commitments of $1.3 billion.

In addition, the credit agreement includes a swing line pursuant to which Bank of America, N.A., as the swing line lender, may make swing line loans in U.S. dollars in an aggregate amount equal to the lesser of (a) $75.0 million and (b) the Aggregate WC Commitments (as defined in the credit agreement). Swing line loans will bear interest at the Base Rate (as defined in the credit agreement). The swing line is a sub-portion of the working capital revolving credit facility and is not an addition to the total available commitments of $1.3 billion.

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

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

Borrowings under the working capital revolving credit facility bear interest at (1) the Eurocurrency rate plus 2.00% to 2.50%, (2) the cost of funds rate plus 2.00% to 2.50%, or (3) the base rate plus 1.00% to 1.50%, each depending on the Utilization Amount (as defined in the credit agreement). Borrowings under the revolving credit facility bear interest at (1) the Eurocurrency rate plus 2.00% to 3.00%, (2) the cost of funds rate plus 2.00% to 3.00%, or (3) the base rate plus 1.00% to 2.00%, each depending on the Combined Total Leverage Ratio (as defined in the credit agreement).

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The credit agreement provides for a letter of credit fee equal to the then applicable working capital rate or then applicable revolver rate (each such rate as defined in the credit agreement) per annum for each letter of credit issued. In addition, we incur a commitment fee on the unused portion of each facility under the credit agreement, ranging from 0.35% to 0.50% per annum.

As of June 30, 2017, we had total borrowings outstanding under the credit agreement of $449.8 million, including $200.7 million outstanding on the revolving credit facility. In addition, we had outstanding letters of credit of $30.2 million. Subject to borrowing base limitations, the total remaining availability for borrowings and letters of credit was $820.0 million and $764.8 million at June 30, 2017 and December 31, 2016, respectively.

The credit agreement is secured by substantially all of our assets and the assets of our wholly owned subsidiaries and is guaranteed by us and our subsidiaries, Bursaw Oil LLC, Global Partners Energy Canada ULC, Warex Terminals Corporation, Drake Petroleum Company, Inc., Puritan Oil Company, Inc. and Maryland Oil Company, Inc.

The credit agreement also includes (i) a $25.0 million general secured indebtedness basket, (ii) a $25.0 million general investment basket, (iii) a $75.0 million secured indebtedness basket to permit the borrowers to enter into a Contango Facility (as defined in the credit agreement), (iv) a Sale/Leaseback Transaction (as defined in the credit agreement) basket of $100.0 million, and (v) a basket of $50.0 million in an aggregate amount over the life of the credit agreement for the purchase of our common units, provided that no Event of Default exists or would occur immediately following such purchase(s).

In addition, the credit agreement provides the ability for the borrowers to repay certain junior indebtedness, subject to a $100.0 million cap, so long as no Event of Default has occurred or will exist immediately after making such repayment.

The credit agreement imposes financial covenants that require us to maintain certain minimum working capital amounts, a minimum combined interest coverage ratio, a maximum senior secured leverage ratio and a maximum total leverage ratio. We were in compliance with the foregoing covenants at June 30, 2017. The credit agreement also contains a representation whereby there can be no event or circumstance, either individually or in the aggregate, that has had or could reasonably be expected to have a Material Adverse Effect (as defined in the credit agreement). In addition, the credit agreement limits distributions by us to our unitholders to the amount of Available Cash (as defined in the partnership agreement).

Senior Notes

We had 6.25% senior notes due 2022 and 7.00% senior notes due 2023 outstanding at June 30, 2017. Please read Note 6 of Notes to Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2016 for additional information on these senior notes.

Financing Obligations

Capitol Acquisition

On June 1, 2015, we acquired retail gasoline stations and dealer supply contracts from Capitol Petroleum Group (“Capitol”). In connection with the acquisition, we assumed a financing obligation of $89.6 million associated with two sale-leaseback transactions by Capitol for 53 leased sites that did not meet the criteria for sale accounting. During the terms of these leases, which expire in May 2028 and September 2029, in lieu of recognizing lease expense for the lease rental payments, we incur interest expense associated with the financing obligation. Interest expense of approximately

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$2.4 million was recorded for each of the three months ended June 30, 2017 and 2016, and $4.8 million was recorded for each of the six months ended June 30, 2017 and 2016, and is included in interest expense in the accompanying statements of operations. The financing obligation will amortize through expiration of the leases based upon the lease rental payments which were $2.4 million for each of the three months ended June 30, 2017 and 2016, and $4.8 million and $4.7 million for the six months ended June 30, 2017 and 2016, respectively. The financing obligation balance outstanding at June 30, 2017 was $89.9 million associated with the Capitol acquisition.

Sale Leaseback Transaction

On June 29, 2016, we, sold to a premier institutional real estate investor (the “Buyer”) real property assets, including the buildings, improvements and appurtenances thereto, at 30 gasoline stations and convenience stores located in Connecticut, Maine, Massachusetts, New Hampshire and Rhode Island (the “Sale Leaseback Sites”) for a purchase price of approximately $63.5 million. In connection with the sale, we entered into a Master Unitary Lease Agreement with the Buyer to lease back the real property assets sold with respect to the Sale Leaseback Sites (such Master Lease Agreement, together with the Sale Leaseback Sites, the “Sale Leaseback Transaction”). The Master Unitary Lease Agreement provides for an initial term of fifteen years that expires in 2031. We have one successive option to renew the lease for a ten-year period followed by two successive options to renew the lease for five-year periods on the same terms, covenants, conditions and rental as the primary non-revocable lease term. We do not have any residual interest nor the option to repurchase any of the sites at the end of the lease term. The proceeds from the Sale Leaseback Transaction were used to reduce indebtedness outstanding under our revolving credit facility.

The sale did not meet the criteria for sale accounting as of June 30, 2017 due to prohibited continuing involvement. Specifically, the sale is considered a partial-sale transaction, which is a form of continuing involvement as we did not transfer to the Buyer the storage tank systems which are considered integral equipment of the Sale Leaseback Sites. Additionally, a portion of the sold sites have material sub-lease arrangements, which is also a form of continuing involvement. As the sale of the Sale-Leaseback Sites did not meet the criteria for sale accounting, we did not recognize a gain or loss on the sale of the Sale Leaseback Sites for the three and six months ended June 30, 2017.

As a result of not meeting the criteria for sale accounting for these sites, the Sale Leaseback Transaction is accounted for as a financing arrangement. As such, the property and equipment sold and leased back by us has not been derecognized and continues to be depreciated. We recognized a corresponding financing obligation of $62.5 million equal to the $63.5 million cash proceeds received for the sale of these sites, net of $1.0 million financing fees. During the term of the lease, which expires in June 2031, in lieu of recognizing lease expense for the lease rental payments, we incur interest expense associated with the financing obligation. Lease rental payments are recognized as both interest expense and a reduction of the principal balance associated with the financing obligation. Interest expense and lease rental payments were $1.1 million and $2.2 million for the three and six months ended June 30, 2017, respectively. Interest expense and lease rental payments were immaterial for the three and six months ended June 30, 2016. The financing obligation balance outstanding at June 30, 2017 was $62.5 million associated with the Sale Leaseback Transaction.

Deferred Financing Fees

We incur bank fees related to our credit agreement and other financing arrangements. These deferred financing fees are capitalized and amortized over the life of the credit agreement or other financing arrangements. In connection with the amendment to the credit agreement in April 2017, we capitalized additional financing fees of $8.0 million for the six months ended June 30, 2017. We had unamortized deferred financing fees of $18.6 million and $14.1 million at June 30, 2017 and December 31, 2016, respectively.

Unamortized fees related to the credit agreement are included in other current assets and other long-term assets and amounted to $11.7 million and $6.5 million at June 30, 2017 and December 31, 2016, respectively. Unamortized fees related to the senior notes are presented as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts, and amounted to $6.0 million and $6.6 million at June 30, 2017 and December 31, 2016, respectively. Unamortized fees related to the Sale-Leaseback Transaction are presented as a direct deduction from the

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carrying amount of the financing obligation and amounted to $0.9 million and $1.0 million at June 30, 2017 and December 31, 2016, respectively.

On April 25, 2017, we entered into the credit agreement, a new facility that has extended the maturity date and reduced the total commitment of the prior credit agreement. As a result, we incurred expenses of approximately $0.6 million associated with the write-off of a portion of the related deferred financing fees. These expenses are included in interest expense in the accompanying statements of operations for each of the three and six months ended June 30, 2017.

On February 24, 2016, under our prior credit agreement, we voluntarily elected to reduce our working capital revolving credit facility from $1.0 billion to $900.0 million and our revolving credit facility from $775.0 million to $575.0 million. As a result, we incurred expenses of approximately $1.8 million associated with the write-off of a portion of the related deferred financing fees. These expenses are included in interest expense in the accompanying statement of operations for the six months ended June 30, 2016.

Amortization expense of approximately $1.4 million and $1.5 million for the three months ended June 30, 2017 and 2016, respectively, and $2.9 million for each of the six months ended June 30, 2017 and 2016, is included in interest expense in the accompanying consolidated statements of operations.

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements.

Critical Accounting Policies and Estimates

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

These estimates are based on our knowledge and understanding of current conditions and actions that we may take in the future. Changes in these estimates will occur as a result of the passage of time and the occurrence of future events. Subsequent changes in these estimates may have a significant impact on our financial condition and results of operations and are recorded in the period in which they become known. We have identified the following estimates that, in our opinion, are subjective in nature, require the exercise of judgment, and involve complex analysis: inventory, leases, revenue recognition, derivative financial instruments, goodwill, evaluation of intangibles, evaluation of 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, 2016. There have been no subsequent changes in these policies and estimates that had a significant impact on our financial condition and results of operations for the periods covered in this report.

Recent Accounting Pronouncements

A description and related impact expected from the adoption of certain new accounting pronouncements is provided in Note 20 of Notes to Consolidated Financial Statements included elsewhere 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 currently utilize an interest rate swap to manage exposure to interest rate risk and various derivative instruments to manage exposure to commodity risk.

Interest Rate Risk

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

As of June 30, 2017, we had total borrowings outstanding under our credit agreement of $449.8 million. Please read Part I, Item 2. “Management’s Discussion and Analysis—Liquidity and Capital Resources—Credit Agreement,” for information on interest rates related to our borrowings. The impact of a 1% increase in the interest rate on this amount of debt would have resulted in an increase in interest expense, and a corresponding decrease in our results of operations, of approximately $4.5 million annually, assuming, however, that our indebtedness remained constant throughout the year.

At June 30, 2017, we had in place one interest rate swap agreement which is hedging $100.0 million of variable rate debt and continues to be accounted for as a cash flow hedge.

See Note 8 of Notes to Consolidated Financial Statements for additional information on our derivative instruments.

Commodity Risk

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

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

We utilize exchange-traded futures contracts and other derivative instruments to minimize or hedge the impact of commodity price changes on our inventories and forward fixed price commitments. Any hedge ineffectiveness is reflected in our results of operations. We utilize regulated exchanges, including the NYMEX, CME and ICE, which are exchanges for the respective commodities that each trades, thereby reducing potential delivery and supply risks. Generally, our practice is to close all exchange positions rather than to make or receive physical deliveries. With respect

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to other products such as ethanol, which may not have a correlated exchange contract, we enter into derivative agreements with counterparties that we believe have a strong credit profile, in order to hedge market fluctuations and/or lock-in margins relative to our commitments.

At June 30, 2017, the fair value of all of our commodity risk derivative instruments and the change in fair value that would be expected from a 10% price increase or decrease are shown in the table below (in thousands):



	Fair Value at		Gain (Loss)
	June 30,		Effect of 10%		Effect of 10%
	2017		Price Increase		Price Decrease
Exchange traded derivative contracts	$	7,809	$	(25,721)	$	25,721
Forward derivative contracts		2,018		1,585		(1,585)
	$	9,827	$	(24,136)	$	24,136

The fair values of the futures contracts are based on quoted market prices obtained from the NYMEX, CME and ICE. The fair value of the swaps and option contracts are estimated based on quoted prices from various sources such as independent reporting services, industry publications and brokers. These quotes are compared to the contract price of the swap, which approximates the gain or loss that would have been realized if the contracts had been closed out at June 30, 2017. 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 $9.4 million at June 30, 2017.

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

Item 4.Controls and Procedures

Disclosure Controls and Procedures

We maintain disclosure controls and procedures that are designed to ensure that the information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act of 1934 (the “Exchange Act”) is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms and that information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure. Under the supervision and with the participation of our principal executive officer and principal financial officer, management evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) or 15d-15(e) of the Exchange Act). Based on this evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were operating and effective as of June 30, 2017.

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Changes in Internal Control Over Financial Reporting

On August 1, 2017, we completed the implementation of new trade capture and transaction processing systems to replace certain of our legacy computer systems used within our Wholesale and Commercial segments. We will continue to make appropriate changes to internal controls and procedures to conform to these new systems. The new systems have automated certain manual processes and standardized business reporting. Management will continue to evaluate and monitor our internal controls as each of the affected areas evolves.

Other than as described above, there were no changes in our internal control over financial reporting that occurred during the quarter ended June 30, 2017 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 10 in this Quarterly Report on Form 10-Q, we are not aware of any significant legal or governmental proceedings against us, or contemplated to be brought against us. We maintain insurance policies with insurers in amounts and with coverage and deductibles as our general partner believes are reasonable and prudent. However, we can provide no assurance that this insurance will be adequate to protect us from all material expenses related to potential future claims or that these levels of insurance will be available in the future at economically acceptable prices.

Other

We determined that gasoline loaded from certain loading bays at one of our terminals did not contain the necessary additives as a result of an IT-related configuration error. The error was corrected and all gasoline being sold at the terminal now contains the appropriate additives. Based upon current information, we believe approximately 14 million gallons of gasoline were impacted. We have notified the EPA of this error. As a result of this error, we could be subject to fines, penalties and other related claims, including customer claims.

In February 2016, we received a request for information from the EPA seeking certain information regarding our Albany terminal in order to assess its compliance with the CAA. The information requested generally related to crude oil received by, stored at and shipped from our petroleum product transloading facility in Albany, New York (the “Albany Terminal”), including its composition, control devices for emissions and various permitting-related considerations. The Albany Terminal is a 63-acre licensed, permitted and operational stationary bulk petroleum storage and transfer terminal that currently consists of petroleum product storage tanks, along with truck, rail and marine loading facilities, for the storage, blending and distribution of various petroleum and related products, including gasoline, ethanol, distillates, heating and crude oils. No violations were alleged in the request for information. We submitted responses and documentation, in March and April 2016, to the EPA in accordance with the EPA request. On August 2, 2016, we received a Notice of Violation (“NOV”) from the EPA, alleging that permits for the Albany Terminal, issued by the New York State Department of Environmental Conservation (“NYSDEC”) between August 9, 2011 and November 7, 2012, violated the CAA and the federally enforceable New York State Implementation Plan (“SIP”) by increasing throughput of crude oil at the Albany Terminal without complying with the New Source Review (“NSR”) requirements of the SIP. The applicable permits issued by the NYSDEC to us in 2011 and 2012 specifically authorize us to increase the throughput of crude oil at the Albany Terminal. According to the allegations in the NOV, the NYSDEC permits should have been regulated as a major modification under the NSR program, requiring additional emission control measures and compliance with other NSR requirements. The NYSDEC has not alleged that our permits were subject to the NSR program. The CAA authorizes the EPA to take enforcement action in response to violations of the New York SIP seeking compliance and penalties. We believe that the permits issued by the NYSDEC comply with the CAA and applicable State air permitting requirements and that no material violation of law has occurred. We dispute the claims alleged in the NOV and responded to the EPA in September, 2016. We met with the EPA and provided additional information at the agency’s request. On December 16, 2016, the EPA proposed a Settlement Agreement in a letter to us relating to the allegations in the NOV. On January 17, 2017, we responded to the EPA indicating that the EPA had failed to explain or provide support for its allegations and that the EPA needed to better explain its positions and the evidence on which it was relying. The EPA did not respond with such evidence but instead requested that the Partnership enter into a further tolling agreement. We have signed a number of tolling agreements with respect to this matter and such agreements currently extend through October 31, 2017. To date, the EPA has not taken any further action with respect to the NOV.

By letter dated October 5, 2015, we received a notice of intent to sue (“October NOI”), which supersedes and replaces a prior notice of intent to sue that we received on September 1, 2015 (the “September NOI”) from Earthjustice,

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an environmental advocacy organization on behalf of the County of Albany, New York, a public housing development owned and operated by the Albany Housing Authority and certain environmental organizations, related to alleged violations of the CAA, particularly with respect to crude oil operations at the Albany Terminal. The October NOI superseded and replaced the September NOI to add two additional environmental advocacy organizations and to revise the relief sought and the description of the alleged CAA violations.

On February 3, 2016, after the NYSDEC chose not to act on the allegations, Earthjustice and the other entities identified in the October NOI filed suit against us in federal court in Albany under the citizen suit provisions of the CAA. In summary, this lawsuit alleges that certain of our operations at the Albany Terminal are in violation of the CAA. The plaintiffs seek, among other things, relief that would compel us both to apply for what the plaintiffs contend is the applicable permit under the CAA, and to install additional pollution controls. In addition, the plaintiffs seek to prohibit the Albany Terminal from receiving, storing, handling, and marine loading certain types of Bakken crude oil and to require payment of a civil penalty of $37,500 for each day we operated the Albany Terminal in violation of the CAA. We believe that we have meritorious defenses against all allegations. On February 26, 2016, we filed a motion to dismiss the CAA action. No decision has yet been issued by the Court and all discovery and other litigation activity is stayed pending a decision by the Court on the motion to dismiss.

By letter dated January 25, 2017, we received a notice of intent to sue (the “2017 NOI”) from Earthjustice related to alleged violations of the CAA; specifically alleging that we were operating the Albany Terminal without a valid CAA Title V Permit. On February 9, 2017, we responded to Earthjustice advising that the 2017 NOI was without factual or legal merit and that we would move to dismiss any action commenced by Earthjustice. No action was taken by either the EPA or the NYSDEC with regard to the Earthjustice allegations. At this time, there has been no further action taken by Earthjustice. Neither the EPA nor the NYSDEC has followed up on the NOI. The Albany Terminal is currently operating pursuant to its Title V Permit. We believe that we have meritorious defenses against all allegations.

On May 29, 2015 and in connection with a commercial dispute with Tethys Trading Company LLC (“Tethys”), we received a notice from Tethys alleging a default under, and purporting to terminate, our contract with Tethys for crude oil services at our Oregon facility. However, we do not believe Tethys had the right to terminate the contract, and we will continue to investigate and determine the appropriate action to take to enforce our rights under the agreement.

On March 26, 2015, we received a Notice of Non-Compliance (“NON”) from the Massachusetts Department of Environmental Protection (“DEP”) with respect to the Revere Terminal, alleging certain violations of the National Pollutant Discharge Elimination System Permit (“NPDES Permit”) related to storm water discharges. The NON required us to submit a plan to remedy the reported violations of the NPDES Permit. We have responded to the NON with a plan and have implemented modifications to the storm water management system at the Revere Terminal in accordance with the plan. We have requested that the DEP acknowledge completion of the required modifications to the storm water management system in satisfaction of the NON. While no response has yet been received, we believe that compliance with the NON has been achieved, and implementation of the plan will have no material impact on our operations.

We received letters from the EPA dated November 2, 2011 and March 29, 2012, containing requirements and testing orders (collectively, the “Requests for Information”) for information under the CAA. The Requests for Information were part of an EPA investigation to determine whether we have violated sections of the CAA at certain of our terminal locations in New England with respect to residual oil and asphalt. On June 6, 2014, a NOV was received from the EPA, alleging certain violations of its Air Emissions License issued by the Maine Department of Environmental Protection, based upon the test results at the South Portland, Maine terminal. We met with and provided additional information to the EPA with respect to the alleged violations. On April 7, 2015, the EPA issued a Supplemental Notice of Violation (the “Supplemental NOV”) modifying the allegations of violations of the terminal’s Air Emissions License. We have responded to the Supplemental NOV and engaged in further negotiations with the EPA. A tolling agreement was executed with the United States on December 1, 2015, which has currently been extended through October 31, 2017. While we do not believe that a material violation has occurred, and we contest the allegations presented in the NOV and Supplemental NOV, we do not believe any adverse determination in connection with the NOV would have a material impact on our operations.

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Item 1A.Risk Factors

In addition to other information set forth in this report, you should carefully consider the factors discussed in Part I, Item 1A, “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2016, which could materially affect our business, financial condition or future results.

Item 6.Exhibits

Exhibits required to be filed by Item 601 of Registration S-K are set forth in the Exhibit Index accompanying this Quarterly Report and are incorporated herein by reference.

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SIGNATURES

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


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


Dated: August 9, 2017		By:	/s/ Eric Slifka
			Eric Slifka
			President and Chief Executive Officer
			(Principal Executive Officer)


Dated: August 9, 2017		By:	/s/ Daphne H. Foster
			Daphne H. Foster
			Chief Financial Officer
			(Principal Financial Officer)

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INDEX TO EXHIBITS


Exhibit Number		Description
3.1	—	Certificate of Limited Partnership of Global Partners LP (incorporated by reference to Exhibit 3.1 to the Registration Statement on Form S-1 filed on May 10, 2005).

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

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

4.2	—	Indenture, dated as of June 4, 2015, among the Issuers, the Guarantors, and Deutsche Bank Trust Company Americas, as trustee (incorporated herein by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on June 4, 2015).

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

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

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

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

101.INS*	—	XBRL Instance Document.
101.SCH*	—	XBRL Taxonomy Extension Schema Document.
101.CAL*	—	XBRL Taxonomy Extension Calculation Linkbase Document.
101.LAB*	—	XBRL Taxonomy Extension Labels Linkbase Document.
101.PRE*	—	XBRL Taxonomy Extension Presentation Linkbase Document.
101.PRE*	—	XBRL Taxonomy Extension Definition Linkbase Document.

*Filed herewith.

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

††Portions of this exhibit have been omitted pursuant to a request for confidential treatment. The omitted information has been filed separately with the Securities and Exchange Commission.

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