GLOBAL PARTNERS LP - Quarter Report: 2016 June (Form 10-Q)

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, 2016

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, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

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

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

The issuer had 33,995,563 common units outstanding as of August 4, 2016.

Table of Contents

TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements (unaudited)		3

Consolidated Balance Sheets as of June 30, 2016 and December 31, 2015		3

Consolidated Statements of Operations for the three and six months ended June 30, 2016 and 2015		4

Consolidated Statements of Comprehensive (Loss) Income for the three and six months ended June 30, 2016 and 2015		5

Consolidated Statements of Cash Flows for the six months ended June 30, 2016 and 2015		6

Consolidated Statement of Partners’ Equity for the six months ended June 30, 2016		7

Notes to Consolidated Financial Statements		8

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		61

Item 3. Quantitative and Qualitative Disclosures About Market Risk		88

Item 4. Controls and Procedures		90

PART II. OTHER INFORMATION		92

Item 1. Legal Proceedings		92

Item 1A. Risk Factors		94

Item 6. Exhibits		94

SIGNATURES		95

INDEX TO EXHIBITS		96

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Item 1.Financial Statements

GLOBAL PARTNERS LP

CONSOLIDATED BALANCE SHEETS

(In thousands, except unit data)

(Unaudited)


	June 30,		December 31,
	2016		2015
Assets
Current assets:
Cash and cash equivalents	$	8,594	$	1,116
Accounts receivable, net		358,142		311,354
Accounts receivable—affiliates		3,862		2,578
Inventories		443,994		388,952
Brokerage margin deposits		39,363		31,327
Derivative assets		29,590		66,099
Prepaid expenses and other current assets		67,678		65,609
Total current assets		951,223		867,035
Property and equipment, net		1,207,239		1,242,683
Intangible assets, net		70,200		75,694
Goodwill		435,369		435,369
Other assets		38,938		42,894
Total assets	$	2,702,969	$	2,663,675
Liabilities and partners’ equity
Current liabilities:
Accounts payable	$	286,807	$	303,781
Working capital revolving credit facility—current portion		218,800		98,100
Environmental liabilities—current portion		5,337		5,350
Trustee taxes payable		96,364		95,264
Accrued expenses and other current liabilities		48,471		60,328
Derivative liabilities		24,088		31,911
Total current liabilities		679,867		594,734
Working capital revolving credit facility—less current portion		150,000		150,000
Revolving credit facility		213,400		269,000
Senior notes		657,866		656,564
Environmental liabilities—less current portion		65,144		67,883
Financing obligations		152,371		89,790
Deferred tax liabilities		79,738		84,836
Other long-term liabilities		56,551		56,884
Total liabilities		2,054,937		1,969,691
Partners’ equity
Global Partners LP equity:
Common unitholders 33,995,563 units issued and 33,519,030 outstanding at June 30, 2016 and 33,995,563 units issued and 33,506,844 outstanding at December 31, 2015)		614,042		657,071
General partner interest (0.67% interest with 230,303 equivalent units outstanding at June 30, 2016 and December 31, 2015)		(1,496)		(1,188)
Accumulated other comprehensive loss		(6,867)		(8,094)
Total Global Partners LP equity		605,679		647,789
Noncontrolling interest		42,353		46,195
Total partners’ equity		648,032		693,984
Total liabilities and partners’ equity	$	2,702,969	$	2,663,675

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,
	2016		2015		2016		2015
Sales	$	2,146,199	$	2,680,088	$	3,897,011	$	5,659,204
Cost of sales		2,016,857		2,535,900		3,637,610		5,346,458
Gross profit		129,342		144,188		259,401		312,746
Costs and operating expenses:
Selling, general and administrative expenses		36,640		45,391		71,624		94,177
Operating expenses		75,891		72,168		148,127		140,824
Amortization expense		2,359		3,070		4,868		8,411
Net loss on sale and disposition of assets and impairment charges		2,530		213		8,635		650
Total costs and operating expenses		117,420		120,842		233,254		244,062
Operating income		11,922		23,346		26,147		68,684
Interest expense		(21,015)		(16,451)		(43,995)		(30,414)
(Loss) income before income tax benefit (expense)		(9,093)		6,895		(17,848)		38,270
Income tax benefit (expense)		550		719		1,470		(247)
Net (loss) income		(8,543)		7,614		(16,378)		38,023
Net loss (income) attributable to noncontrolling interest		1,233		(396)		2,044		(390)
Net (loss) income attributable to Global Partners LP		(7,310)		7,218		(14,334)		37,633
Less: General partner’s interest in net (loss) income, including incentive distribution rights		(49)		2,671		(96)		4,850
Limited partners’ interest in net (loss) income	$	(7,261)	$	4,547	$	(14,238)	$	32,783
Basic net (loss) income per limited partner unit	$	(0.22)	$	0.15	$	(0.42)	$	1.06
Diluted net (loss) income per limited partner unit	$	(0.22)	$	0.15	$	(0.42)	$	1.06
Basic weighted average limited partner units outstanding		33,518		31,037		33,518		30,819
Diluted weighted average limited partner units outstanding		33,518		31,214		33,518		30,978

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

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GLOBAL PARTNERS LP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME

(In thousands)

(Unaudited)


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2016		2015		2016		2015
Net (loss) income	$	(8,543)	$	7,614	$	(16,378)	$	38,023
Other comprehensive income:
Change in fair value of cash flow hedges		592		1,295		853		1,478
Change in pension liability		306		(269)		374		(178)
Total other comprehensive income		898		1,026		1,227		1,300
Comprehensive (loss) income		(7,645)		8,640		(15,151)		39,323
Comprehensive loss (income) attributable to noncontrolling interest		1,233		(396)		2,044		(390)
Comprehensive (loss) income attributable to Global Partners LP	$	(6,412)	$	8,244	$	(13,107)	$	38,933

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,
	2016		2015
Cash flows from operating activities
Net (loss) income	$	(16,378)	$	38,023
Adjustments to reconcile net (loss) income to net cash used in operating activities:
Depreciation and amortization		57,949		55,240
Amortization of deferred financing fees		2,948		2,927
Amortization of leasehold interests		626		172
Amortization of senior notes discount		690		411
Bad debt expense		50		288
Unit-based compensation expense		2,150		2,072
Write-off of financing fees		1,828		—
Net loss on sale and disposition of assets and impairment charges		8,635		650
Changes in operating assets and liabilities, excluding net assets acquired:
Accounts receivable		(46,838)		90,971
Accounts receivable-affiliate		(1,284)		(1,372)
Inventories		(55,042)		(72,788)
Broker margin deposits		(8,036)		(1,792)
Prepaid expenses, all other current assets and other assets		(2,277)		3,749
Accounts payable		(16,974)		(145,863)
Trustee taxes payable		1,100		(17,225)
Change in derivatives		28,686		24,232
Accrued expenses, all other current liabilities and other long-term liabilities		(17,816)		(36,927)
Net cash used in operating activities		(59,983)		(57,232)
Cash flows from investing activities
Acquisitions		—		(561,757)
Capital expenditures		(38,846)		(33,163)
Proceeds from sale of property and equipment		11,682		1,251
Net cash used in investing activities		(27,164)		(593,669)
Cash flows from financing activities
Proceeds from issuance of common units, net		—		109,305
Net borrowings from working capital revolving credit facility		120,700		168,200
Net (payments on) borrowings from revolving credit facility		(55,600)		134,200
Proceeds from sale-leaseback, net		62,476		—
Proceeds from senior notes, net of discount		—		295,125
Payments on line of credit		—		(700)
Repurchase of common units		—		(2,442)
Noncontrolling interest capital contribution		—		1,880
Distribution to noncontrolling interest		(1,798)		(3,600)
Distributions to partners		(31,153)		(45,118)
Net cash provided by financing activities		94,625		656,850
Cash and cash equivalents
Increase in cash and cash equivalents		7,478		5,949
Cash and cash equivalents at beginning of period		1,116		5,238
Cash and cash equivalents at end of period	$	8,594	$	11,187
Supplemental information
Cash paid during the period for interest	$	23,016	$	25,117

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, 2015	$	657,071	$	(1,188)	$	(8,094)	$	46,195	$	693,984
Net (loss) income		(14,238)		(96)		—		(2,044)		(16,378)
Distribution to noncontrolling interest		—		—		—		(1,798)		(1,798)
Other comprehensive income		—		—		1,227		—		1,227
Unit-based compensation		2,150		—		—		—		2,150
Distributions to partners		(31,446)		(212)		—		—		(31,658)
Dividends on repurchased units		505		—		—		—		505
Balance at June 30, 2016	$	614,042	$	(1,496)	$	(6,867)	$	42,353	$	648,032

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 domestic and Canadian crude oil, gasoline and gasoline blendstocks (such as ethanol), distillates (such as home heating oil, diesel and kerosene), residual oil, renewable fuels, natural gas and propane. The Partnership also receives revenue from convenience store sales and gasoline station rental income. 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 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 to the East and West Coasts. 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. As of June 30, 2016, the Partnership had a portfolio of 1,511 owned, leased and/or supplied gasoline stations, including 290 directly operated convenience stores, in the Northeast, Maryland and Virginia.

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 GMG.

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, 2016, affiliates of the General Partner, including its directors and executive officers and their affiliates, owned 7,434,775 common units, representing a 21.9% limited partner interest.

Recent Transactions

Sale Leaseback Transaction—On June 29, 2016, the Partnership and its wholly owned subsidiaries Global Companies LLC (“Global Companies”), Global Montello Group Corp. (“GMG”) and Alliance Energy LLC (“Alliance”), and Alliance’s wholly owned subsidiary, Bursaw Oil LLC (“Bursaw”) 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, the Partnership, 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 6.

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

Basis of Presentation

On January 7, 2015, the Partnership acquired, through one of its wholly owned subsidiaries, GMG, 100% of the equity interests in Warren Equities, Inc. (“Warren”) from The Warren Alpert Foundation. On January 14, 2015, the Partnership acquired the Revere terminal (the “Revere Terminal”) located in Boston Harbor in Revere, Massachusetts from Global Petroleum Corp. (“GPC”) and related entities. On June 1, 2015, the Partnership acquired, through one of its wholly owned subsidiaries, Alliance, retail gasoline stations and dealer supply contracts from Capitol Petroleum Group (“Capitol”). See Note 2.

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The financial results of Capitol for the one month ended June 30, 2015 are included in the accompanying statements of operations for the three and six months ended June 30, 2015. The financial results of Warren and the Revere Terminal for the three and six months ended June 30, 2015 are included in the accompanying statements of operations for the three and six months ended June 30, 2015. The accompanying consolidated financial statements as of June 30, 2016 and December 31, 2015 and for the three and six months ended June 30, 2016 and 2015 reflect the accounts of the Partnership. Upon consolidation, all intercompany balances and transactions have been eliminated.

The accompanying unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) and reflect all adjustments (consisting of normal recurring adjustments) which are, in the opinion of management, necessary for a fair presentation of the financial condition and operating results for the interim periods. The interim financial information, which has been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”), should be read in conjunction with the consolidated financial statements for the year ended December 31, 2015 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, 2016 are not necessarily indicative of the results of operations that will be realized for the entire year ending December 31, 2016. The consolidated balance sheet at December 31, 2015 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, 2015.

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.

Noncontrolling Interest

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

The Partnership acquired a 60% interest in Basin Transload, LLC (“Basin Transload”) on February 1, 2013. After evaluating ASC 810, 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.

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Concentration of Risk

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,
	2016		2015		2016		2015
Gasoline sales: gasoline and gasoline blendstocks (such as ethanol)	68	%	62	%	63	%	56	%
Crude oil sales and crude oil logistics revenue	7	%	13	%	8	%	11	%
Distillates (home heating oil, diesel and kerosene), residual oil, natural gas and propane sales	20	%	21	%	25	%	30	%
Convenience store sales, rental income and sundry sales	5	%	4	%	4	%	3	%
Total	100	%	100	%	100	%	100	%

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,
	2016		2015		2016		2015
Wholesale segment	21	%	37	%	23	%	40	%
GDSO segment	75	%	59	%	73	%	55	%
Commercial segment	4	%	4	%	4	%	5	%
Total	100	%	100	%	100	%	100	%

See Note 10, “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, 2016 and 2015.

Goodwill

Goodwill represents the future economic benefits arising from assets acquired in a business combination that are not individually identified and separately recognized. The Partnership has concluded that its operating segments are also its reporting units. At June 30, 2016 and December 31, 2015, goodwill recorded in the accompanying consolidated balance sheets aggregated $435.4 million, of which $121.7 million relates to the Wholesale reporting unit and $313.7 million relates to the Gasoline Distribution and Station Operations (“GDSO”) reporting unit. Goodwill associated with the Partnership’s disposition activities of GDSO sites will be included in the carrying value of assets sold in determining the gain or loss on disposal. No goodwill has been derecognized as of June 30, 2016.

Goodwill is tested for impairment annually as of October 1 or when events or changes in circumstances indicate that the carrying amount of goodwill may not be recoverable. The process of testing goodwill for impairment involves numerous judgments, assumptions and estimates made by management which inherently reflect a high degree of uncertainty. The impairment test first includes a qualitative assessment in order to conclude if it is more likely than not that the reporting unit’s fair value exceeds its carrying value. Factors considered in the qualitative analysis include changes in the business and industry, as well as macro-economic conditions, that would influence the fair value of the reporting unit as well as changes in the carrying values of the reporting unit. If necessary, the Partnership will then complete a two-step quantitative assessment. In the quantitative assessment, the fair value of each reporting unit is determined and compared to the book value of the reporting unit. If the fair value of the reporting unit is less than the

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

book value, including goodwill, then the recorded goodwill is impaired to its implied fair value with a charge to operations. The Partnership calculates the fair value of each reporting unit using a combination of discounted cash flows and market comparables.

Key assumptions included in the development of the discounted cash flow value for each reporting unit include:

Future commodity volumes and margins. The discounted cash flows are based on a five-year forecast with an estimate of terminal values. In general, the reporting units’ fair values are most sensitive to volume and gross margin assumptions. In particular, the Wholesale segment’s cash flows are impacted by the crude oil market, given the Partnership’s 2013 investment in transloading terminals in North Dakota and Oregon. The significant decline in the price of crude oil and tight crude oil differentials negatively impacted the Partnership’s fiscal 2015 results. The Partnership expects low crude oil prices and tight differentials to continue for a period of time, which has negatively impacted and will continue to negatively impact the Partnership’s 2016 performance, with forecasted recovery expected sometime in 2017. However, with the continuation of low crude oil prices and tight differentials, the Partnership’s assumptions as to the timing of a market recovery, particularly in crude oil, might be more extended than currently estimated within the Partnership’s five-year forecast and estimate of terminal values. If market conditions do not improve or timing of recovery is extended and does not become more certain, the Partnership may change such assumptions in future periods. As a result of these market conditions, there is increased uncertainty and sensitivity relating to the Partnership’s future cash flow projections within its crude oil business on which the Wholesale reporting unit’s goodwill impairment analysis relies. If market conditions, and therefore the Partnership’s performance, are worse than its projections, the Partnership may record impairment charges in the future. Actual results may not be consistent with these judgments, assumptions and estimates, and goodwill impairment charges may be required in future periods. This could have an adverse impact on the Partnership’s financial position and results of operations.

Discount rate commensurate with the risks involved. The Partnership applies a discount rate to its expected cash flows based on a variety of factors, including market and economic conditions, operational risk, regulatory risk and political risk. A higher discount rate decreases the net present value of cash flows.

Future capital requirements. The Partnership’s estimates of future capital requirements are based upon a combination of authorized spending and internal forecasts.

On October 1, 2015, the Partnership completed its quantitative assessments for both the Wholesale and GDSO reporting units, and no impairment indicator was identified for either reporting unit. The declining crude oil prices, changes in certain market conditions and decline in the Partnership’s common unit price, collectively caused the Partnership to reassess its goodwill for impairment as of December 31, 2015 for the Wholesale reporting unit. Based on the results of this assessment, the Partnership concluded that step two of the quantitative assessment was not necessary and no impairment was required.

As of June 30, 2016, the Partnership considered whether there was any change of circumstances or events during the second quarter which would more likely than not reduce the fair value of the Wholesale segment’s reporting unit below its carrying amount. The Partnership concluded that such events and circumstances have not occurred. However, with the continuation of low crude oil prices and tight differentials, the Partnership’s assumptions as to the timing of a market recovery, particularly in crude oil, might be more extended than currently estimated within the Partnership’s five-year forecast and estimate of terminal values. If market conditions do not improve or timing of recovery is extended and does not become more certain, the Partnership may change such assumptions in future periods, which could result in a different conclusion. The Partnership continues to monitor the extent and timing of future demand, which may impact the timing of forecasted recovery.

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The fair values of the Partnership’s reporting units are based on underlying assumptions that represent the Partnership’s best estimates. Many of the factors used in assessing fair value are outside of the control of management. A further sustained decline in commodity prices may cause the Partnership to reassess its long-lived assets and goodwill for impairment and could result in future non-cash impairment charges as a result of such impairment assessments. If the Partnership is required to perform step two in the future for the Wholesale reporting unit, up to $121.7 million of goodwill assigned to this reporting unit could be written off in the period of such impairment assessment.

Note 2. Business Combinations

2015 Acquisitions

Warren Equities, Inc.—On January 7, 2015, the Partnership acquired, through GMG, 100% of the equity interests in Warren, one of the largest independent marketers of petroleum products in the Northeast, from The Warren Alpert Foundation. The acquisition included 147 company-owned Xtra Mart convenience stores and related fuel operations, 53 commission agent locations and fuel supply rights for approximately 330 dealers. The acquired properties are located in the Northeast, Maryland and Virginia. The purchase price, inclusive of post-closing adjustments, was approximately $381.8 million, including working capital. The acquisition was funded with borrowings under the Partnership’s credit facility and with proceeds from its December 2014 public offering of 3,565,000 common units.

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

In connection with the acquisition of Warren, the Partnership recorded acquisition costs of approximately $1.0 million and $5.4 million for the three and six months ended June 30, 2015, respectively, which are included in selling, general and administrative expenses in the accompanying consolidated statements of operations. Additionally, in January 2015 and subsequent to the acquisition date, the Partnership recorded a restructuring charge of approximately $2.3 million, which is included in selling, general and administrative expenses in the accompanying consolidated statement of operations for the six months ended June 30, 2015. Approximately $0 and $0.5 million of the restructuring charge was paid during the three and six months ended June 30, 2015, respectively, and the remaining balance of $1.8 million was paid during the year ended December 31, 2015.

Revere Terminal—On January 14, 2015, through the Partnership’s wholly owned subsidiary, Global Companies, the Partnership acquired the Revere Terminal located in Boston Harbor in Revere, Massachusetts from GPC, a privately held affiliate of the Partnership, and related entities for a purchase price of $23.7 million. The acquisition includes contingent consideration which would be payable under specific circumstances involving a subsequent sale of the property during the eight years following the acquisition. The contingent consideration was estimated to be $0 as of the acquisition date as the Partnership concluded that the sale of the terminal for non-petroleum use within the eight years following the acquisition is not probable. There have been no changes to this assessment since the acquisition date. The Partnership financed the transaction with borrowings under its revolving credit facility. In connection with the Revere Terminal transaction, the pre-existing terminal storage rental and throughput agreement between the Partnership and GPC was terminated.

The acquisition was accounted for using the purchase method of accounting in accordance with the FASB’s guidance regarding business combinations. As the acquisition transitioned the Revere Terminal from a formerly leased facility to an owned facility, the transaction did not have a material impact on the Partnership’s consolidated financial statements.

Capitol Petroleum Group—On June 1, 2015, the Partnership acquired 97 primarily Mobil and Exxon branded owned or leased retail gasoline stations and seven dealer supply contracts in New York City and Prince George’s

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County, Maryland, along with certain related supply and franchise agreements and third-party leases and other assets associated with the operations from Liberty Petroleum Realty, LLC, East River Petroleum Realty, LLC, Big Apple Petroleum Realty, LLC, White Oak Petroleum, LLC, Anacostia Realty, LLC, Mount Vernon Petroleum Realty, LLC and DAG Realty, LLC (collectively, “Capitol Petroleum Group”). The purchase price was approximately $155.7 million. The acquisition was financed with borrowings under the Partnership’s revolving credit facility.

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

In connection with the acquisition of Capitol, the Partnership incurred acquisition costs of approximately $3.1 million which was recorded for each of the three and six months ended June 30, 2015 and included in selling, general and administrative expenses in the accompanying consolidated statements of operations.

Supplemental Pro Forma Information—Revenues and net income not included in the Partnership’s consolidated operating results for Warren from January 1, 2015 through January 7, 2015, the acquisition date, were immaterial. Accordingly, the supplemental pro forma information for the six months ended June 30, 2015 is consistent with the amounts reported in the accompanying consolidated statement of operations for the six months ended June 30, 2015 as it relates to Warren.

The following unaudited pro forma information presents the consolidated results of operations of the Partnership for the three and six months ended June 30, 2015 as if the acquisition of Capitol occurred on January 1, 2015 (in thousands, except per unit data):


	Three Months Ended		Six Months Ended
	June 30, 2015		June 30, 2015
Sales	$	2,797,134	$	5,911,504
Net income attributable to Global Partners LP	$	6,611	$	39,422
Net income per limited partner unit, basic and diluted	$	0.13	$	1.12

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

Under the Partnership’s partnership agreement, for any quarterly period, the incentive distribution rights (“IDRs”) participate in net income only to the extent of the amount of cash distributions actually declared, thereby excluding the IDRs from participating in the Partnership’s undistributed net income or losses. Accordingly, the Partnership’s undistributed net income 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, 2016 and December 31, 2015 excluded 476,553 and 488,719 common units, respectively, held on behalf of the Partnership pursuant to its repurchase program (see Note 13). These units are not deemed outstanding for purposes of calculating net (loss) income per limited partner unit (basic and diluted).

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The following table provides a reconciliation of net (loss) income and the assumed allocation of net (loss) income to the limited partners’ interest for purposes of computing net (loss) income per limited partner unit for the three and six months ended June 30, 2016 and 2015 (in thousands, except per unit data):


	Three Months Ended June 30, 2016								Three Months Ended June 30, 2015
			Limited		General						Limited		General
			Partner		Partner						Partner		Partner
Numerator:	Total		Interest		Interest		IDRs		Total		Interest		Interest		IDRs
Net (loss) income attributable to Global Partners LP (1)	$	(7,310)	$	(7,261)	$	(49)	$	—	$	7,218	$	4,547	$	2,671	$	—
Declared distribution	$	15,829	$	15,723	$	106	$	—	$	26,320	$	23,543	$	159	$	2,618
Assumed allocation of undistributed net (loss) income		(23,139)		(22,984)		(155)		—		(19,102)		(18,996)		(106)		—
Assumed allocation of net (loss) income	$	(7,310)	$	(7,261)	$	(49)	$	—	$	7,218	$	4,547	$	53	$	2,618

Denominator:
Basic weighted average limited partner units outstanding				33,518								31,037
Dilutive effect of phantom units				—								177
Diluted weighted average limited partner units outstanding				33,518								31,214
Basic net (loss) income per limited partner unit			$	(0.22)							$	0.15
Diluted net (loss) income per limited partner unit (2)			$	(0.22)							$	0.15

(1)

As a result of the June 2015 issuance of 3,000,000 common units, the general partner interest was reduced to 0.67% for the three months ended June 30, 2016 and, based on a weighted average, 0.73% for the three months ended June 30, 2015.

(2)

Basic units were used to calculate diluted net income 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 income per limited partner unit.

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	Six Months Ended June 30, 2016								Six Months Ended June 30, 2015
			Limited		General						Limited		General
			Partner		Partner						Partner		Partner
Numerator:	Total		Interest		Interest		IDRs		Total		Interest		Interest		IDRs
Net (loss) income attributable to Global Partners LP (1)	$	(14,334)	$	(14,238)	$	(96)	$	—	$	37,633	$	32,783	$	4,850	$	—
Declared distribution	$	31,658	$	31,446	$	212	$	—	$	49,580	$	44,619	$	316	$	4,645
Assumed allocation of undistributed net (loss) income		(45,992)		(45,684)		(308)		—		(11,947)		(11,836)		(111)		—
Assumed allocation of net (loss) income	$	(14,334)	$	(14,238)	$	(96)	$	—	$	37,633	$	32,783	$	205	$	4,645

Denominator:
Basic weighted average limited partner units outstanding				33,518								30,819
Dilutive effect of phantom units				—								159
Diluted weighted average limited partner units outstanding				33,518								30,978
Basic net (loss) income per limited partner unit			$	(0.42)							$	1.06
Diluted net (loss) income per limited partner unit (2)			$	(0.42)							$	1.06

(1)

As a result of the June 2015 issuance of 3,000,000 common units, the general partner interest was reduced to 0.67% for the six months ended June 30, 2016 and, based on a weighted average, 0.73% for the six months ended June 30, 2015.

(2)

Basic units were used to calculate diluted net income 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 income per limited partner unit.

During 2016, 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 26, 2016	$	0.4625	March 31, 2016
July 27, 2016	$	0.4625	June 30, 2016

See Note 8, “Partners’ Equity and Cash Distributions” for further information.

Note 4. 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, is 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 market, 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 market.

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

Inventories consisted of the following (in thousands):


	June 30,		December 31,
	2016		2015
Distillates: home heating oil, diesel and kerosene	$	170,653	$	156,411
Gasoline		76,018		62,467
Gasoline blendstocks		38,145		32,542
Crude oil		119,748		102,253
Residual oil		17,622		12,895
Propane and other		851		1,469
Renewable identification numbers (RINs)		562		803
Convenience store inventory		20,395		20,112
Total	$	443,994	$	388,952

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 $8.0 million and $3.4 million at June 30, 2016 and December 31, 2015, respectively. Negative exchange balances are accounted for as accounts payable and amounted to $13.6 million and $12.1 million at June 30, 2016 and December 31, 2015, respectively. Exchange transactions are valued using current carrying costs.

Note 5. 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 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.

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The following table summarizes the notional values related to the Partnership’s derivative instruments outstanding at June 30, 2016:


	Units (1)		Unit of Measure
Exchange-Traded Derivatives
Long		58,999	Thousands of barrels
Short		(61,531)	Thousands of barrels

OTC Derivatives (Petroleum/Ethanol)
Long		7,721	Thousands of barrels
Short		(5,209)	Thousands of barrels

OTC Derivatives (Natural Gas)
Long		13,617	Thousands of decatherms
Short		(12,819)	Thousands of decatherms

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

Foreign Currency Derivatives	$	1.4	Millions of Canadian dollars
Open Forward Exchange Contracts (2)	$	1.1	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.

(2)

All-in forward rate Canadian dollars $1.2967 to USD $1.00.

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.

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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 three and six months ended June 30, 2016 and 2015 (in thousands):


	Statement of Gain (Loss)	Three Months Ended				Six Months Ended
	Recognized in Income on	June 30,				June 30,
	Derivatives	2016		2015		2016		2015
Derivatives in fair value hedging relationship
Exchange-traded futures contracts and OTC derivative contracts for petroleum commodity products	Cost of sales	$	(45,891)	$	(16,609)	$	(18,052)	$	9,567

Hedged items in fair value hedge relationship
Physical inventory	Cost of sales	$	52,663	$	17,289	$	28,488	$	(6,332)

Cash Flow Hedges

Derivatives designated as cash flow hedges are used to hedge interest rate risk from fluctuations in interest rates and may include various interest rate derivative instruments entered into with major financial institutions. For a derivative instrument being designated as a cash flow hedge, the effective portion of the derivative gain or loss is initially reported as a component of other comprehensive income (loss) and subsequently reclassified into the consolidated statement of operations through interest expense in the same period that the hedged exposure affects earnings. The ineffective portion is recognized in the consolidated statement of operations immediately.

The Partnership’s cash flow hedges for the three and six months ended June 30, 2016 and 2015 included interest rate swaps and an interest rate cap that were hedges of variability in forecasted interest payments due to changes in the interest rate on LIBOR-based borrowings, a summary of which includes the following designations:

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

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

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

In the aggregate, these hedging instruments have historically been effective in hedging the variability in interest payments due to changes in the one month LIBOR swap curve or rate with respect to $300.0 million of one month LIBOR based borrowings on the credit facility. In June 2014 and as a result of the issuance of the Partnership’s $375.0 million aggregate principal amount of its 6.25% senior notes due 2022 (see Note 6), the Partnership determined that maintaining an excess of $300.0 million in principal of outstanding floating-rate debt was no longer probable. Therefore, the Partnership elected to de-designate its interest rate cap and discontinued the related hedge accounting for this instrument. The interest rate cap, which expired on April 13, 2016, was not in a hedging relationship for the three and six months ended June 30, 2016 and 2015. Accordingly, all changes in fair value of this instrument subsequent to the date of de-designation were recorded in the consolidated statement of operations through interest expense.

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At June 30, 2016, 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 following table presents the amount of gains and losses from the Partnership’s derivative instruments designated in cash flow hedging relationships recognized in the consolidated statements of operations and partners’ equity for the three and six months ended June 30, 2016 and 2015 (in thousands):


	Amount of Gain (Loss)				Location of Gain (Loss)	Amount of Gain (Loss)
	Recognized in				Reclassified from	Reclassified from
	Other Comprehensive				Accumulated Other	Other Comprehensive
	Income on Derivatives				Comprehensive Income into	Income into Income
	(Effective Portion)				Income (Effective Portion)	(Effective Portion)
	Three Months Ended					Three Months Ended
Derivatives Designated in	June 30,					June 30,
Cash Flow Hedging Relationship	2016		2015			2016		2015
Interest rate swaps	$	511	$	1,132	Interest expense	$	—	$	—
Interest rate cap		—		(5)	Interest expense		—		—
Total	$	511	$	1,127		$	—	$	—


	Amount of Gain (Loss)				Location of Gain (Loss)	Amount of Gain (Loss)
	Recognized in				Reclassified from	Reclassified from
	Other Comprehensive				Accumulated Other	Other Comprehensive
	Income on Derivatives				Comprehensive Income into	Income into Income
	(Effective Portion)				Income (Effective Portion)	(Effective Portion)
	Six Months Ended					Six Months Ended
Derivatives Designated in	June 30,					June 30,
Cash Flow Hedging Relationship	2016		2015			2016		2015
Interest rate swaps	$	539	$	1,179	Interest expense	$	—	$	—
Interest rate cap		—		(5)	Interest expense		—		—
Total	$	539	$	1,174		$	—	$	—

The amount of gain (loss) recognized in income as ineffectiveness for derivatives designated in cash flow hedging relationships was $0 for the three and six months ended June 30, 2016 and 2015.

Derivatives Not Accounted for as Hedges

The Partnership utilizes petroleum and ethanol commodity contracts, natural gas commodity contracts and foreign currency derivatives to hedge price and currency risk in certain commodity inventories and physical forward contracts.

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.

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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.

Natural Gas Commodity Contracts

The Partnership uses physical forward purchase contracts to hedge price risk associated with the marketing and selling of natural gas to third-party users. These physical forward purchase commitments for natural gas are typically executed when the Partnership enters into physical forward sale commitments of product for physical delivery. These physical forward contracts, to the extent they meet the definition of a derivative, are reflected as derivative assets and derivative liabilities in the consolidated balance sheet. Changes in fair value of the forward purchase and sale commitments are recognized in the consolidated statement of operations through cost of sales.

Foreign Currency Contracts

The Partnership uses forward foreign currency contracts to hedge certain foreign denominated (Canadian) commodity product purchases. These forward foreign currency contracts are not designated by the Partnership as hedges and are reflected as prepaid expenses and other current assets or accrued expenses and other current liabilities in the consolidated balance sheets. Changes in fair values of these forward foreign currency contracts are reflected in 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 three and six months ended June 30, 2016 and 2015 (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	2016		2015		2016		2015
Commodity contracts	Cost of sales	$	326	$	863	$	(89)	$	4,513
Forward foreign currency contracts	Cost of sales		64		14		103		32
Total		$	390	$	877	$	14	$	4,545

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 Contract Derivatives and Other Derivative Activity

The Partnership’s commodity contract derivatives 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

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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.

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, 2016 and December 31, 2015 (in thousands):


		June 30, 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	$	4,023	$	31,014	$	35,037
Forward derivative contracts (1)	Derivative assets		—		29,590		29,590
Forward foreign currency contracts	Other assets		—		9		9
Total asset derivatives		$	4,023	$	60,613	$	64,636

Liability Derivatives:
Exchange-traded derivative contracts	Broker margin deposits	$	11,503	$	71,759	$	83,262
Forward derivative contracts (1)	Derivative liabilities		—		24,088		24,088
Interest rate swap contracts	Other long-term liabilities		—		2,804		2,804
Total liability derivatives		$	11,503	$	98,651	$	110,154


		December 31, 2015
		Derivatives		Derivatives Not
		Designated as		Designated as
		Hedging		Hedging
	Balance Sheet Location	Instruments		Instruments		Total
Asset Derivatives:
Exchange-traded derivative contracts	Broker margin deposits	$	83,645	$	11,722	$	95,367
Forward derivative contracts (1)	Derivative assets		—		66,099		66,099
Forward foreign currency contracts	Other assets		—		10		10
Total asset derivatives		$	83,645	$	77,831	$	161,476

Liability Derivatives:
Forward derivative contracts (1)	Derivative liabilities	$	—	$	31,911	$	31,911
Interest rate swap contracts	Other long-term liabilities		—		3,343		3,343
Total liability derivatives		$	—	$	35,254	$	35,254

(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

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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.

Note 6. Debt and Financing Obligations

Credit Agreement

Certain subsidiaries of the Partnership, as borrowers, and the Partnership and certain of its subsidiaries, as guarantors, have a senior secured credit facility (the “Credit Agreement”). On February 24, 2016, the Partnership entered into the fifth amendment to the Credit Agreement (the “Fifth Amendment”) which reflects, among other things, the Partnership’s voluntary election 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, for a total available commitment of $1.475 billion. The Credit Agreement will mature on April 30, 2018.

As of June 30, 2016, the two facilities under the Credit Agreement included:

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

a $575.0 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 of its then-existing credit agreement, provided no Event of Default (as defined in the Credit Agreement) then exists, an increase to the working capital revolving credit facility, the revolving credit facility, or both, by up to another $300.0 million, in the aggregate, for a total credit facility of up to $1.775 billion. 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 $1.475 billion.

In addition, the Credit Agreement includes a swing line pursuant to which Bank of America, N.A., as the swing line lender, may make swing line loans in U.S. Dollars in an aggregate amount equal to the lesser of (a) $50.0 million and (b) the Aggregate WC Commitments (as defined in the Credit Agreement). Swing line loans will bear interest at the Base Rate (as defined in the Credit Agreement). The swing line is a sub-portion of the working capital revolving credit facility and is not an addition to the total available commitments of $1.475 billion.

Pursuant to the Credit Agreement, and in connection with any agreement by and between a Loan Party and a Lender (as such terms are defined in the Credit Agreement) or affiliate thereof (an “AR Buyer”), a Loan Party may sell certain of its accounts receivables to an AR Buyer. The Loan Parties are permitted to sell or transfer any account receivable to an AR Buyer only pursuant to the provisions provided in the Credit Agreement. To date, the level of receivables sold has not been significant, and the Partnership has accounted for such transfers as sales pursuant to ASC 860, “Transfers and Servicing.” Due to the short term nature of the receivables sold to date, no servicing obligation has been recorded because it would have been de minimis.

Availability under the working capital revolving credit facility is subject to a borrowing base which is redetermined from time to time 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

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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.

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). Pursuant to the Fifth Amendment, borrowings under the revolving credit facility bear interest at (1) the Eurocurrency rate plus 2.25% to 3.50%, (2) the cost of funds rate plus 2.25% to 3.50%, or (3) the base rate plus 1.25% to 2.50%, each depending on the Combined Total Leverage Ratio (as defined in the Credit Agreement).

The average interest rates for the Credit Agreement were 3.5% and 3.4% for the three months ended June 30, 2016 and 2015, respectively, and 3.7% and 3.4% for the six months ended June 30, 2016 and 2015, respectively.

As of June 30, 2016, the Partnership had one interest rate swap which was used to hedge the variability in interest payments under the Credit Agreement due to changes in LIBOR rates. See Note 5 for additional information.

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

The Partnership classifies a portion of its working capital revolving credit facility as a 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, 2016, the Partnership estimated working capital revolving credit facility borrowings will equal or exceed $150.0 million over the next 12 months and, therefore, classified $218.8 million as the current portion at June 30, 2016, representing the amount the Partnership expects to pay down over the next 12 months. The long-term portion of the working capital revolving credit facility was $150.0 million and $150.0 million at June 30, 2016 and December 31, 2015, respectively, and the current portion was $218.8 million and $98.1 million at June 30, 2016 and December 31, 2015, respectively. The increase in total borrowings under the working capital revolving credit facility of $120.7 million from December 31, 2015 was primarily due to cash used in operating assets and liabilities during the year. Inventory and accounts receivable increased due to higher prices, and accounts payable decreased as the Partnership exited the heating season. Lower crude oil volume also contributed to the decline in accounts payable.

As of June 30, 2016, the Partnership had total borrowings outstanding under the Credit Agreement of $582.2 million, including $213.4 million outstanding on the revolving credit facility. In addition, the Partnership had outstanding letters of credit of $66.9 million. Subject to borrowing base limitations, the total remaining availability for borrowings and letters of credit was $825.9 million and $1.2 billion at June 30, 2016 and December 31, 2015, 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 with the exception of Basin Transload.

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

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merger, consolidation, sale leaseback transaction or purchase of assets or make capital expenditures in excess of specified levels.

The Credit Agreement imposes financial covenants that require the Partnership to maintain certain minimum working capital amounts, a minimum combined interest coverage ratio, a maximum senior secured leverage ratio and a maximum total leverage ratio. The Fifth Amendment amended the definition of “Total Combined Leverage Ratio” to permit for an increased maximum ratio of 5.50:1.00 through the first quarter of 2017 and 5.0:1.00 thereafter. The Partnership was in compliance with the foregoing covenants at June 30, 2016. 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).

6.25% Senior Notes

On June 19, 2014, the Partnership and GLP Finance Corp. (“GLP Finance” and, together with the Partnership, the “Issuers”) entered into a Purchase Agreement (the “Purchase Agreement”) with the Initial Purchasers (as defined therein) (the “Initial Purchasers”) pursuant to which the Issuers agreed to sell $375.0 million aggregate principal amount of the Issuers’ 6.25% senior notes due 2022 (the “6.25% Notes”) to the Initial Purchasers in a private placement exempt from the registration requirements under the Securities Act of 1933, as amended (the “Securities Act”). The 6.25% Notes were resold by the Initial Purchasers to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to persons outside the United States pursuant to Regulation S under the Securities Act.

The Purchase Agreement contained customary representations and warranties of the parties and indemnification and contribution provisions under which the Issuers and the subsidiary guarantors, on one hand, and the Initial Purchasers, on the other, agreed to indemnify each other against certain liabilities, including liabilities under the Securities Act. In addition, the Purchase Agreement required the execution of a registration rights agreement, described below, relating to the 6.25% Notes. Closing of the offering occurred on June 24, 2014.

Indenture

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

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

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July 15, 2017, the Issuers may redeem all or any part of the 6.25% Notes at a redemption price equal to the sum of the principal amount thereof, plus a make whole premium at the redemption date, plus accrued and unpaid interest, if any, to the redemption date. The holders of the notes may require the Issuers to repurchase the 6.25% Notes following certain asset sales or a Change of Control (as defined in the Indenture) at the prices and on the terms specified in the Indenture.

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

Registration Rights Agreement

On June 24, 2014, the Issuers and the subsidiary guarantors entered into a registration rights agreement (the “Registration Rights Agreement”) with the Initial Purchasers in connection with the Issuers’ private placement of the 6.25% Notes. Under the Registration Rights Agreement, the Issuers and the subsidiary guarantors agreed to file and use commercially reasonable efforts to cause to become effective a registration statement relating to an offer to exchange the 6.25% Notes for an issue of SEC-registered notes with terms identical to the 6.25% Notes (except that the exchange notes are not subject to restrictions on transfer or to any increase in annual interest rate for failure to comply with the Registration Rights Agreement) that are registered under the Securities Act so as to permit the exchange offer to be consummated by the 360th day after June 24, 2014. The exchange offer was completed on April 21, 2015, and 100% of the 6.25% Notes were exchanged for SEC-registered notes.

7.00% Senior Notes

On June 1, 2015, the Issuers entered into a Purchase Agreement (the “7.00% Notes Purchase Agreement”) with the Initial Purchasers (as defined therein) (the “7.00% Notes Initial Purchasers”) pursuant to which the Issuers agreed to sell $300.0 million aggregate principal amount of the Issuers’ 7.00% senior notes due 2023 (the “7.00% Notes”) to the 7.00% Notes Initial Purchasers in a private placement exempt from the registration requirements under the Securities Act. The 7.00% Notes were resold by the 7.00% Notes Initial Purchasers to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to persons outside the United States pursuant to Regulation S under the Securities Act.

The 7.00% Notes Purchase Agreement contained customary representations and warranties of the parties and indemnification and contribution provisions under which the Issuers and the subsidiary guarantors, on one hand, and the 7.00% Notes Initial Purchasers, on the other, agreed to indemnify each other against certain liabilities, including liabilities under the Securities Act. In addition, the 7.00% Notes Purchase Agreement required the execution of a registration rights agreement, described below, relating to the 7.00% Notes. Closing of the offering occurred on June 4, 2015.

Indenture

In connection with the private placement of the 7.00% Notes on June 4, 2015 the Issuers and the subsidiary guarantors and Deutsche Bank Trust Company Americas, as trustee, entered into an indenture (the “7.00% Notes Indenture”).

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The 7.00% Notes will mature on June 15, 2023 with interest accruing at a rate of 7.00% per annum and payable semi-annually in arrears on June 15 and December 15 of each year, commencing December 15, 2015. The 7.00% Notes are guaranteed on a joint and several senior unsecured basis by each of the Issuers and the subsidiary guarantors to the extent set forth in the 7.00% Notes Indenture. Upon a continuing event of default, the trustee or the holders of at least 25% in principal amount of the 7.00% Notes may declare the 7.00% Notes immediately due and payable, except that an event of default resulting from entry into a bankruptcy, insolvency or reorganization with respect to the Partnership, any restricted subsidiary of the Partnership that is a significant subsidiary or any group of its restricted subsidiaries that, taken together, would constitute a significant subsidiary of the Partnership, will automatically cause the 7.00% Notes to become due and payable.

The Issuers will have the option to redeem up to 35% of the 7.00% Notes prior to June 15, 2018 at a redemption price (expressed as a percentage of principal amount) of 107.00% plus accrued and unpaid interest, if any. The Issuers have the option to redeem the 7.00% Notes, in whole or in part, at any time on or after June 15, 2018, at the redemption prices of 105.250% for the twelve-month period beginning June 15, 2018, 103.500% for the twelve-month period beginning June 15, 2019, 101.750% for the twelve-month period beginning June 15, 2020, and 100.0% beginning June 15, 2021 and at any time thereafter, together with any accrued and unpaid interest to the date of redemption. In addition, before June 15, 2018, the Issuers may redeem all or any part of the 7.00% Notes at a redemption price equal to the sum of the principal amount thereof, plus a make whole premium, plus accrued and unpaid interest, if any, to the redemption date. The holders of the 7.00% Notes may require the Issuers to repurchase the 7.00% Notes following certain asset sales or a Change of Control (as defined in the 7.00% Notes Indenture) at the prices and on the terms specified in the 7.00% Notes Indenture.

The 7.00% Notes Indenture contains covenants that will limit the Partnership’s ability to, among other things, incur additional indebtedness and issue preferred securities, make certain dividends and distributions, make certain investments and other restricted payments, restrict distributions by its subsidiaries, create liens, enter into sale-leaseback transactions, sell assets or merge with other entities. Events of default under the 7.00% Notes Indenture include (i) a default in payment of principal of, or interest or premium, if any, on, the 7.00% Notes, (ii) breach of the Partnership’s covenants under the 7.00% Notes Indenture, (iii) certain events of bankruptcy and insolvency, (iv) any payment default or acceleration of indebtedness of the Partnership or certain subsidiaries if the total amount of such indebtedness unpaid or accelerated exceeds $50.0 million and (v) failure to pay within 60 days uninsured final judgments exceeding $50.0 million.

Registration Rights Agreement

On June 4, 2015, the Issuers and the subsidiary guarantors entered into a registration rights agreement (the “7.00% Notes Registration Rights Agreement”) with the 7.00% Notes Initial Purchasers in connection with the Issuers’ private placement of the 7.00% Notes. Under the 7.00% Notes Registration Rights Agreement, the Issuers and the subsidiary guarantors agreed to file and use commercially reasonable efforts to cause to become effective a registration statement relating to an offer to exchange the 7.00% Notes for an issue of SEC-registered notes with terms identical to the 7.00% Notes (except that the exchange notes are not subject to restrictions on transfer or to any increase in annual interest rate for failure to comply with the 7.00% Notes Registration Rights Agreement) that are registered under the Securities Act so as to permit the exchange offer to be consummated by the 420th day after June 4, 2015. The exchange offer was completed on October 22, 2015, and 100% of the 7.00% Notes were exchanged for SEC-registered notes.

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Financing Obligations

Capitol Acquisition

In connection with the Capitol acquisition on June 1, 2015 (see Note 2), 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 term 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 and $0.8 million was recorded for the three months ended June 30, 2016 and 2015, respectively, and $4.8 million and $0.8 million was recorded for the six months ended June 30, 2016 and 2015, respectively, and is included in interest expense in the accompanying statements of operations. The financing obligation will amortize through expiration of the lease based upon the lease rental payments which were $2.4 million and $0.8 million for the three months ended June 30, 2016 and 2015, respectively, and $4.7 million and $0.8 million for the six months ended June 30, 2016 and 2015, respectively. The financing obligation balance outstanding at June 30, 2016 was $89.9 million associated with the Capitol acquisition.

Sale Leaseback Transaction

On June 29, 2016, the Partnership, through its wholly owned subsidiaries, Global Companies, GMG and Alliance, and Alliance’s wholly owned subsidiary, Bursaw, 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 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, 2016 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, 2016, respectively.

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 will continue 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 will incur interest expense associated with the financing obligation. Lease rental payments will be recognized as both interest expense and a reduction of the principal balance associated with the financing obligation. 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, 2016 was $62.5 million associated with the Sale Leaseback Transaction.

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The following provides future minimum lease payments, which are subject to annual adjustments based on a consumer price index based calculation, for the non-cancelable operating lease for each of the next five years ending December 31:


2016 (7/1/16 - 12/31/16)	$	2,205
2017		4,411
2018		4,411
2019		4,411
2020		4,411
Thereafter		46,286
Total	$	66,135

The following provides future minimum sublease rentals from third-party tenants of the sold Sale Leaseback Sites for each of the next five years ending December 31:


2016 (7/1/16 - 12/31/16)	$	972
2017		1,315
2018		692
2019		256
2020		169
Total	$	3,404

Total rental income from third-party tenants of the sold Sale Leaseback Sites was immaterial for the three and six months ended June 30, 2016.

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. The Partnership capitalized additional financing fees of $1.0 million for each of the three and six months ended June 30, 2016, including recording, deed transfer, survey and legal fees associated with the financing obligation recognized as part of the Sale Leaseback Transaction. The Partnership had unamortized deferred financing fees of $17.2 million and $19.0 million at June 30, 2016 and December 31, 2015, respectively.

Unamortized fees related to the Credit Agreement are included in other current assets and other long-term assets and amounted to $9.0 million and $11.2 million at June 30, 2016 and December 31, 2015, 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 $7.2 million and $7.8 million at June 30, 2016 and December 31, 2015, 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 $1.0 million at June 30, 2016.

On February 24, 2016, 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-off of a portion of its 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 $1.5 million and $1.4 million for the three months ended June 30, 2016 and 2015, respectively, and $2.9 million and $2.9 million for the six months ended June 30, 2016 and 2015, respectively, is included in interest expense in the accompanying consolidated statements of operations.

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Note 7. Related Party Transactions

The Partnership was a party to an exclusive Second Amended and Restated Terminal Storage Rental and Throughput Agreement, as amended (the “Terminal Storage Rental and Throughput Agreement”), with GPC, an affiliate of the Partnership that is 100% owned by members of the Slifka family, with respect to the Revere Terminal in Revere, Massachusetts. On January 14, 2015, the Partnership acquired the Revere Terminal from GPC and related entities, and the Terminal Storage Rental and Throughput Agreement was terminated. Prior to the acquisition, the agreement was accounted for as an operating lease. The expenses under this agreement totaled $0.8 million for the six months ended June 30, 2015.

The Partnership was a party to an Amended and Restated Services Agreement with GPC, whereby GPC provided certain terminal operating management services to the Partnership and used certain administrative, accounting and information processing services of the Partnership. The expenses from these services totaled approximately $8,000 for the six months ended June 30, 2015.

On March 11, 2015, the Partnership entered into the following amendments and restatements to its shared services agreements: (i) Global Companies entered into an Amended and Restated Services Agreement with AE Holdings Corp. (the “AE Holdings Amended and Restated Services Agreement”), and (ii) certain of the Partnership’s subsidiaries entered into a Second Amended and Restated Services Agreement with GPC (the “GPC Second Amended and Restated Services Agreement”).

Under the AE Holdings Amended and Restated Services Agreement, the Partnership provided AE Holdings with certain tax, accounting, treasury and legal support services for which AE Holdings paid the Partnership an aggregate of $15,000 per year in equal monthly installments until it was voluntarily dissolved effective on July 10, 2015. Under the GPC Second Amended and Restated Services Agreement, GPC no longer provides the Partnership with terminal, environmental and operational support services, but the Partnership continues to provide 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 GPC Second Amended and Restated Services Agreement is for an indefinite term and any party may terminate some or all of the services upon ninety (90) days’ advanced written notice. As of June 30, 2016, 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 $22.9 million and $26.8 million for the three months ended June 30, 2016 and 2015, respectively, and $48.6 million and $56.2 million for the six months ended June 30, 2016 and 2015, 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.

Receivables from the General Partner, which primarily include the Partnership’s prepayment of payroll taxes and payroll accruals to the General Partner, were $3.9 million and $2.6 million and recorded in accounts receivable-affiliates in the accompanying balance sheets at June 30, 2016 and December 31, 2015, respectively.

Note 8. Partners’ Equity and Cash Distributions

Partners’ Equity

Partners’ equity at June 30, 2016 consisted of 33,995,563 common units issued, including 7,434,775 common units held by affiliates of the General Partner, including directors and executive officers, collectively representing a

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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, 2016.

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 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 2016 (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
2/16/2016	12/31/15	$	0.4625	$	15,723	$	106	$	—	$	15,829
5/16/2016	03/31/16		0.4625		15,723		106		—		15,829

In addition, on July 27, 2016, 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, 2016 through June 30, 2016 to the Partnership’s unitholders of record as of the close of business on August 8, 2016.

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Note 9. Unitholders’ Equity

Equity Offering

On June 11, 2015, the Partnership entered into an underwriting agreement relating to the public offering of 3,000,000 common units at a price to the public of $38.12 per common unit. On June 16, 2015, the Partnership completed the offering, and the net proceeds of approximately $109.3 million (after deducting underwriting discounts and estimated expenses) were used to reduce indebtedness outstanding under the Partnership’s revolving credit facility.

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.

As of June 30, 2016, no common units were sold by the Partnership pursuant to the at-the-market offering program.

Note 10. Segment Reporting

The Partnership engages in the purchasing, selling, storing and logistics of transporting petroleum and related products, including domestic and Canadian crude oil, gasoline and gasoline blendstocks (such as ethanol), distillates (such as home heating oil, diesel and kerosene), residual oil, renewable fuels, natural gas and propane. The Partnership also receives revenue from convenience store sales and gasoline station rental income. The Partnership’s operating segments are based upon the revenue sources for which discrete financial information is reviewed by the chief operating decision maker (the “CODM”) and include Wholesale, GDSO and Commercial. Each of these operating segments generates revenues and incurs expenses and is evaluated for operating performance on a regular basis.

These operating segments are also the Partnership’s reporting segments based on the way the CODM manages the business and on the similarity of customers and expected long-term financial performance of each segment. For the three and six months ended June 30, 2016 and 2015, the Commercial operating segment did not meet the quantitative

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metrics for disclosure as a reportable segment on a stand-alone basis as defined in accounting guidance related to segment reporting. However, the Partnership has elected to present segment disclosures for the Commercial operating segment as management believes such disclosures are helpful to the user of the Partnership’s financial information. The accounting policies of the segments are the same as those described in Note 2, “Summary of Significant Accounting Policies,” in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2015.

In the Wholesale reporting segment, the Partnership sells branded and unbranded gasoline and gasoline blendstocks and diesel to wholesale distributors. The Partnership transports these products by railcars, barges and/or pipelines pursuant to spot or long‑term contracts. The Partnership aggregates crude oil by truck or pipeline in the mid-continent region of the United States and Canada, transports it by train and ships it by barge to refiners on the East Coast. The Partnership sells home heating oil, 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 the Partnership owns or controls or with which it has throughput or exchange arrangements. Additionally, ethanol is shipped primarily by rail and by barge.

In the GDSO reporting 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).

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

The Partnership evaluates segment performance based on product margins before allocations of corporate and indirect operating costs, depreciation, amortization (including non-cash charges) and interest. Based on the way the CODM manages the business, it is not reasonably possible for the Partnership to allocate the components of operating costs and expenses among the reportable segments.

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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,
	2016		2015		2016		2015
Wholesale Segment:
Sales
Gasoline and gasoline blendstocks	$	594,411	$	718,971	$	937,140	$	1,495,114
Crude oil (1)		160,595		363,880		309,097		615,990
Other oils and related products (2)		318,123		401,083		737,132		1,344,776
Total	$	1,073,129	$	1,483,934	$	1,983,369	$	3,455,880
Product margin
Gasoline and gasoline blendstocks	$	26,612	$	17,708	$	42,974	$	47,537
Crude oil (1)		(9,648)		36,828		(12,021)		52,085
Other oils and related products (2)		15,804		6,405		41,053		41,412
Total	$	32,768	$	60,941	$	72,006	$	141,034
Gasoline Distribution and Station Operations Segment:
Sales
Gasoline	$	815,634	$	906,511	$	1,431,737	$	1,603,845
Station operations (3)		101,058		98,417		186,243		181,492
Total	$	916,692	$	1,004,928	$	1,617,980	$	1,785,337
Product margin
Gasoline	$	66,999	$	53,209	$	132,386	$	114,908
Station operations (3)		49,267		45,066		92,192		81,789
Total	$	116,266	$	98,275	$	224,578	$	196,697
Commercial Segment:
Sales	$	156,378	$	191,226	$	295,662	$	417,987
Product margin	$	5,480	$	7,023	$	12,390	$	18,581
Combined sales and Product margin:
Sales	$	2,146,199	$	2,680,088	$	3,897,011	$	5,659,204
Product margin (4)	$	154,514	$	166,239	$	308,974	$	356,312
Depreciation allocated to cost of sales		(25,172)		(22,051)		(49,573)		(43,566)
Combined gross profit	$	129,342	$	144,188	$	259,401	$	312,746

(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 primarily consist of convenience store sales and rental income.

(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 121 million gallons and 115 million gallons of the GDSO segment’s sales for the three months ended June 30, 2016 and 2015, respectively, and 232 million gallons and 226 million gallons of the GDSO segment’s sales for the six months ended June 30, 2016 and 2015, respectively, were supplied from petroleum products and renewable fuels sourced by the Wholesale segment. Except for natural gas, 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,
	2016		2015		2016		2015
Combined gross profit	$	129,342	$	144,188	$	259,401	$	312,746
Operating costs and expenses not allocated to operating segments:
Selling, general and administrative expenses		36,640		45,391		71,624		94,177
Operating expenses		75,891		72,168		148,127		140,824
Amortization expense		2,359		3,070		4,868		8,411
Net loss on sale and disposition of assets and impairment charges		2,530		213		8,635		650
Total operating costs and expenses		117,420		120,842		233,254		244,062
Operating income		11,922		23,346		26,147		68,684
Interest expense		(21,015)		(16,451)		(43,995)		(30,414)
Income tax benefit (expense)		550		719		1,470		(247)
Net (loss) income		(8,543)		7,614		(16,378)		38,023
Net loss (income) attributable to noncontrolling interest		1,233		(396)		2,044		(390)
Net income attributable to Global Partners LP	$	(7,310)	$	7,218	$	(14,334)	$	37,633

The Partnership’s foreign assets and foreign sales were immaterial as of and for the three and six months ended June 30, 2016 and 2015.

Segment Assets

The Partnership’s terminal assets are allocated to the Wholesale and Commercial segments, and its acquired 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, 2016 and December 31, 2015 (in thousands):


		Wholesale		Commercial		GDSO		Unallocated		Total
June 30, 2016	$	811,817	$	1,000	$	1,363,653	$	526,499	$	2,702,969
December 31, 2015	$	774,352	$	3,224	$	1,392,397	$	493,702	$	2,663,675

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Note 11. Property and Equipment

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


	June 30,		December 31,
	2016		2015
Buildings and improvements	$	1,007,163	$	992,917
Land		437,185		450,045
Fixtures and equipment		40,340		40,946
Construction in process		76,708		67,080
Capitalized internal use software		18,852		18,852
Total property and equipment		1,580,248		1,569,840
Less accumulated depreciation		373,009		327,157
Total	$	1,207,239	$	1,242,683

Property and equipment includes assets held for sale of $44.7 million and $7.4 million at June 30, 2016 and December 31, 2015, respectively (see Note 15).

Construction in process

At June 30, 2016 and December 31, 2015, construction in process included $30.5 million related to the Partnership’s ethanol plant acquired from Cascade Kelly Holdings LLC (“Cascade Kelly”) in 2013. The Partnership began taking steps to utilize this location by shifting the terminalling facility from crude oil to ethanol transloading. This measure was substantially related to cleaning of tanks and modifications to associated infrastructure, which commenced during the first quarter of 2016 and was completed early in the third quarter of 2016.

Therefore, as of June 30, 2016 and December 31, 2015, the recorded value of the ethanol plant was included in construction in process. After the plant has been successfully placed into service, depreciation will commence.

Evaluation of Impairment

The Partnership evaluates its assets for impairment on a quarterly basis. As a result of its analysis, an impairment of two discrete asset groups was required, and the Partnership recorded an impairment charge of $2.2 million for the three and six months ended June 30, 2016, which is included in net loss on sale and disposition of assets and impairment charges in the accompanying consolidated statements of operations.

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 long-term recoverability of these assets has been adversely impacted by the decline in commodity prices and the cost differential between natural gas and oil. As oil has remained an attractive alternative to CNG due to lower oil prices, the related impact on the CNG operating and cash flows was determined to be an impairment indicator, resulting in the impairment of the CNG long-lived assets during the three and six months ended June 30, 2016. The method used for determining fair value of the CNG assets predominately relied on the market approach. The CNG assets are allocated to the Commercial segment. Additionally, 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. The method used for determining fair value of this GDSO site predominately relied on the market approach.

At June 30, 2016, the Partnership had a $42.1 million remaining net book value of long-lived assets used at its crude oil transloading terminals in North Dakota. The long-term recoverability of these assets may be adversely impacted by a prolonged decline in crude oil prices or crude oil differentials. Over the long-term, if these market

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conditions remain, this may become an indicator of the potential impairment of these North Dakota assets in the future. The Partnership will monitor the pricing environment and the related impact this may have on the North Dakota operating and cash flows and whether this would constitute an impairment indicator.

At June 30, 2016, the Partnership had a $66.2 million remaining net book value of long-lived assets used at its West Coast facility and had substantially completed with the measures necessary to shift the facility from crude oil to ethanol transloading. The Partnership will need to take certain measures to prepare the facility for ethanol production to place the plant in service. 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. The Partnership will 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.

Note 12. Environmental Liabilities, Asset Retirement Obligations and Renewable Identification Numbers

Environmental Liabilities

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

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

In connection with the June 2015 acquisition of retail gasoline stations from Capitol, the Partnership assumed certain environmental liabilities, including future remediation activities required by applicable federal, state or local law or regulation at certain of the retail gasoline stations owned by Capitol. Certain environmental remediation obligations at most of the acquired retail gasoline station assets from Capitol are being funded by third parties who assumed certain liabilities in connection with Capitol’s acquisition of these assets from ExxonMobil Corporation (“ExxonMobil”) in 2009 and 2010 and, therefore, cost estimates for such obligations at these stations are not included in this estimate of liability to the Partnership. As a result, the Partnership initially recorded, on an undiscounted basis, a total environmental liability of approximately $0.3 million for those locations not covered by third parties.

In connection with the January 2015 acquisition of the Revere Terminal, the Partnership assumed certain environmental liabilities, including certain ongoing environmental remediation efforts. As a result, the Partnership initially recorded, on an undiscounted basis, a total environmental liability of approximately $3.1 million.

In connection with the January 2015 acquisition of Warren, the Partnership assumed certain environmental liabilities, including certain ongoing environmental remediation efforts at certain of the retail gasoline stations owned or leased by Warren and future remediation activities required by applicable federal, state or local law or regulation. As a

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result, the Partnership initially recorded, on an undiscounted basis, a total environmental liability of approximately $36.5 million.

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

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

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

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

In addition to the above-mentioned environmental liabilities related to the Partnership's retail gasoline stations, the Partnership retains some of the environmental obligations associated with certain gasoline stations that the Partnership has sold.

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The following table presents a summary roll forward of the Partnership’s environmental liabilities at June 30, 2016 (in thousands):


	Balance at						Other		Balance at
	December 31,		Payments in		Dispositions		Adjustments		June 30,
Environmental Liability Related to:	2015		2016		2016		2016		2016
Retail gasoline stations	$	68,451	$	(2,037)	$	(750)	$	150	$	65,814
Terminals		4,782		(115)		—		—		4,667
Total environmental liabilities	$	73,233	$	(2,152)	$	(750)	$	150	$	70,481
Current portion	$	5,350							$	5,337
Long-term portion		67,883								65,144
Total environmental liabilities	$	73,233							$	70,481

The Partnership’s estimates used in these environmental liabilities are based on all known facts at the time and its assessment of the ultimate remedial action outcomes. Among the many uncertainties that impact the Partnership’s estimates are the necessary regulatory approvals for, and potential modification of, its remediation plans, the amount of data available upon initial assessment of the impact of soil or water contamination, changes in costs associated with environmental remediation services and equipment, relief of obligations through divestures of sites and the possibility of existing legal claims giving rise to additional claims. Dispositions generally represent relief of legal obligations through the sale of the related property 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 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. The associated asset retirement costs are capitalized as part of the carrying cost of the asset. The Partnership had approximately $8.1 million and $7.8 million in total asset retirement obligations at June 30, 2016 and December 31, 2015, 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 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

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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 $0.1 million and $0.4 million at June 30, 2016 and December 31, 2015, respectively.

The Partnership may enter into RIN forward purchase and sales commitments. Total losses from firm non-cancellable commitments were immaterial at June 30, 2016 and December 31, 2015.

Note 13. 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 under the LTIP are authorized by the Compensation Committee of the board of directors of the General Partner (the “Committee”) from time to time. Additionally and in accordance with the LTIP, the Committee established a “CEO Authorized LTIP” program pursuant to which the Chief Executive Officer (“CEO”) may grant awards of phantom units without distribution equivalent rights to employees of the General Partner and the Partnership’s subsidiaries, other than named executive officers. The CEO Authorized LTIP program was approved for three consecutive calendar years commencing January 1, 2014, subject to modification or earlier termination by the Committee. During each calendar year of the program, the CEO is authorized to grant awards of up to an aggregate amount of $2.0 million of phantom units payable in common units upon vesting, with unused dollar amounts carrying over in the next year, and no individual grant may be made for an award valued at the time of grant of more than $550,000, unless otherwise previously approved by the Committee. Awards granted pursuant to the CEO Authorized LTIP generally would be for a term of six years and vest in equal tranches at the end of each of the fourth, fifth and sixth anniversary dates of the particular award.

Phantom Unit Awards

In 2013, the Committee granted a total of 498,112 phantom units under the LTIP to certain employees and non-employee directors of the General Partner. In 2014, a total of 44,902 phantom units were granted to certain employees. In 2015, a total of 76,893 phantom units were granted to certain employees and the non-employee directors. No awards were granted during the three and six months ended June 30, 2016.

The phantom units for these awards vest pursuant to the terms of the grant agreements. The Partnership currently intends and reasonably expects to issue and deliver the common units upon vesting.

The Partnership recorded total compensation expense related to the above awards of $1.1 million and $1.1 million for the three months ended June 30, 2016 and 2015, respectively, and $2.2 million and $2.1 million for the six months ended June 30, 2016 and 2015, respectively, which is included in selling, general and administrative expenses in the accompanying consolidated statements of operations. The total compensation cost related to the non-vested awards not

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yet recognized at June 30, 2016 was approximately $12.2 million and is expected to be recognized ratably over the remaining requisite service periods.

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, 2015	595,720		38.85
Vested	(10,659)		35.94
Forfeited	(1,527)		32.75
Outstanding non—vested units at June 30, 2016	583,534		38.92

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 has repurchased 838,505 common units pursuant to the Repurchase Program for approximately $24.8 million. No units were purchased during the three and six months ended June 30, 2016.

Note 14. Fair Value Measurements

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Partnership utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. The Partnership primarily applies the market approach for recurring fair value measurements and endeavors to utilize the best available information. Accordingly, the Partnership utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The Partnership is able to classify fair value balances based on the observability of those inputs. The fair value hierarchy that prioritizes the inputs used to measure fair value, giving the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement).

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At each balance sheet reporting date, the Partnership categorizes its financial assets and liabilities using the three levels of the fair value hierarchy defined as follows:


Level 1	—	Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as the Partnership’s exchange-traded derivative instruments and pension plan assets.

Level 2	—	Quoted prices in active markets are not available; however, pricing inputs are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Level 2 primarily consists of non-exchange-traded derivatives such as OTC derivatives.

Level 3	—	Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. Level 3 includes certain OTC forward derivative instruments related to crude oil and propane.

Recurring Fair Value Measures

Assets and liabilities are classified in the entirety based on the lowest level of input that is significant to the fair value measurement. The Partnership’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value assets and liabilities and their placement within the fair value hierarchy levels.

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, 2016 and December 31, 2015 (in thousands):


	Fair Value at June 30, 2016
							Cash Collateral
	Level 1		Level 2		Level 3		Netting		Total
Assets:
Forward derivative contracts (1)	$	—	$	27,081	$	2,427	$	—	$	29,508
Foreign currency derivatives		—		9		—		—		9
Swap agreements and options		—		82		—		—		82
Exchange-traded/cleared derivative instruments (2)		(48,226)		—		—		87,589		39,363
Pension plan		16,607		—		—		—		16,607
Total assets	$	(31,619)	$	27,172	$	2,427	$	87,589	$	85,569

Liabilities:
Forward derivative contracts (1)	$	—	$	(22,880)	$	(1,208)	$	—	$	(24,088)
Interest rate swaps		—		(2,804)		—		—		(2,804)
Total liabilities	$	—	$	(25,684)	$	(1,208)	$	—	$	(26,892)

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	Fair Value at December 31, 2015
							Cash Collateral
	Level 1		Level 2		Level 3		Netting		Total
Assets:
Forward derivative contracts (1)	$	—	$	62,382	$	3,717	$	—	$	66,099
Foreign currency derivatives		—		10		—		—		10
Exchange-traded/cleared derivative instruments (2)		95,367		—		—		(64,040)		31,327
Pension plan		16,886		—		—		—		16,886
Total assets	$	112,253	$	62,392	$	3,717	$	(64,040)	$	114,322

Liabilities:
Forward derivative contracts (1)	$	—	$	(27,602)	$	(3,653)	$	—	$	(31,255)
Swap agreements and options		—		(656)		—		—		(656)
Interest rate swaps		—		(3,343)		—		—		(3,343)
Total liabilities	$	—	$	(31,601)	$	(3,653)	$	—	$	(35,254)

(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.

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 5.

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 values of the Level 1 exchange-traded/cleared derivative instruments and pension plan assets were determined using quoted prices in active markets for identical assets. Specifically, the fair values of the Level 1 exchange-traded/cleared derivative instruments were based on quoted process obtained from the NYMEX, CME and ICE. The fair values of the Level 1 pension plan assets were based on quoted prices for identical assets which primarily consisted of fixed income securities, equity securities and cash and cash equivalents.

The values of the Level 2 derivative contracts were calculated using expected cash flow models and market approaches based on observable market inputs, including published and quoted commodity pricing data, which is verified against other available market data. Specifically, the fair values of the Level 2 derivative commodity contracts were derived from published and quoted NYMEX, CME, ICE, New York Harbor and third-party pricing information for the underlying instruments using market approaches. The fair value of the Level 2 interest rate instruments were derived from the implied forward LIBOR yield curve for the sale period as the future interest rate swap and interest rate cap settlements using expected cash flow models. The fair value of the Level 2 foreign currency derivatives were derived from the implied forward currency curve for the Canadian and U.S. Dollar. The Partnership has not changed its valuation techniques or Level 2 inputs during the six months ended June 30, 2016.

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The fair values of the 6.25% Notes and 7.00% Notes, estimated by observing market trading prices of the 6.25% Notes and 7.00% Notes, respectively, were as follows (in thousands):


	June 30, 2016					December 31, 2015
	Face			Fair		Face		Fair
	Value			Value		Value		Value
6.25% Notes		$	375,000	$	309,844	$	375,000	$	307,500
7.00% Notes		$	300,000	$	247,875	$	300,000	$	249,000

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 $2.35 to $12.50 per barrel and $4.00 to $13.55 per barrel as of June 30, 2016 and December 31, 2015, respectively. The estimates for these inputs for propane were $0.42 to $10.50 per barrel and $2.10 to $9.66 per barrel as of June 30, 2016 and December 31, 2015, respectively. Gains and losses recognized in earnings (or changes in net assets) are disclosed in Note 5.

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)

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, 2016 (in thousands):


Fair value at December 31, 2015	$	64
Transfers into Level 3		—
Derivatives entered into during the period		1,097
Realized gains (losses) recorded in cost of sales		147
Unrealized gains (losses) recorded in cost of sales		(89)
Fair value at June 30, 2016	$	1,219

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.

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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 or losses related to firm non-cancellable purchase commitments. 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 11 for a discussion of the Partnership’s losses on impairment of assets and Note 15 for assets held for sale.

Note 15. Sales and Disposition of Assets and Impairment Charges

The following table provides the Partnership’s (gain) loss on sale and dispositions of assets and impairment charges for the three and six months ended June 30, 2016 and 2015 (in thousands):


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2016		2015		2016		2015
Periodic divesture of gasoline stations	$	78	$	—	$	657	$	210
Strategic asset divesture program		—		—		—		—
Loss on assets held for sale		108		—		5,644		—
Losses on impairment of assets		2,155		—		2,155		—
Other		189		213		179		440
Total	$	2,530	$	213	$	8,635	$	650

Periodic Divesture 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 at disposition, net of settlement and dispositions costs, is recorded in net loss on sale and disposition of assets and impairment charges in the accompanying consolidated statements of operations and amounted to $78,000 and $0 for the three months ended June 30, 2016 and 2015, respectively, and $0.6 million and $0.2 million for the six months ended June 30, 2016 and 2015, respectively.

Strategic Asset Divesture Program

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

On May 26, 2016, Drake Petroleum Company, Inc., an indirect wholly owned subsidiary of the Partnership executed a purchase and sale agreement with Mirabito Holdings, Inc. (“Mirabito”) for the sale of 31 gasoline stations and convenience stores (see Note 20). These sites are included in the Divesture Program and met the criteria to be presented as held for sale as of June 30, 2016.

The Partnership has retained a real estate firm in the second quarter of 2016 that is coordinating the sale of 90 non-strategic GDSO sites. These sites are included in the Divesture Program and did not meet the criteria to be presented as held for sale as of June 30, 2016. In July 2016, such criteria was met for 32 of these 90 sites (see Note 20).

As there were no sales of sites within the Divesture Program for the three and six months ending June 30, 2016, the Partnership has not recognized a gain or loss on the sale.

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Loss on Assets Held for Sale

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

The Partnership classified 25 sites and 15 sites as held for sale at June 30, 2016 and December 31, 2015, respectively, which are periodic divestiture gasoline station sites. The Partnership recorded impairment charges related to its assets held for sale in the amount of $0.1 million and $0 for the three months ended June 30, 2016 and 2015, respectively, and $5.6 million and $0 for the six months ended June 30, 2016 and 2015, respectively, which are included in net loss on sale and disposition of assets and impairment charges in the accompanying consolidated statements of operations.

Additionally, the Partnership classified 31 sites associated with the Mirabito transaction discussed above and in Note 20 as held for sale at June 30, 2016. 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 $44.7 million and $7.4 million at June 30, 2016 and December 31, 2015, 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.

Losses on Impairment of Assets

The Partnership recognized an impairment charge of $1.9 million associated with the long-lived assets used in supplying CNG which is viewed as an alternative fuel to oil. The CNG assets are allocated to the Commercial segment. In addition, the Partnership recognized an impairment charge of $0.3 million associated with the long-lived assets of one discrete GDSO site. See Note 11 for additional information.

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 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.

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

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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, 2016 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, 2016, 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. As of June 30, 2016, the Partnership had $0.8 million of unrecognized tax benefits, of which $0.7 million would favorably impact the effective tax rate if recognized. As of December 31, 2015, the Partnership had $0.1 million of unrecognized tax benefits, of which none would favorably impact the effective tax rate if recognized. The Partnership’s unrecognized tax benefits were increased by $0.7 million for the three and six months ended June 30, 2016 due to establishing a reserve for a potential tax assessment related to an ongoing state income tax audit.

As of June 30, 2016, unrecognized tax benefits for uncertain tax positions could change up to $0.8 million in the next 12 months as a result of settlements or filing accounting method changes with the Internal Revenue Service. The Partnership’s policy is to recognized interest and penalties related to uncertain tax positions as a component of its provision for income taxes. Approximately $0.1 million of gross interest and penalties were accrued as of June 30, 2016. There was a tax expense associated with accrued interest and penalties of $0.1 million for the three and six months ended June 30, 2016.

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GMG files income tax returns in the United State and various state jurisdictions. With few exceptions, the Partnership is subject to income tax examination by tax authorities for all years dated back to 2012.

Note 17. Legal Proceedings

General

Although the Partnership may, from time to time, be involved in litigation and claims arising out of its operations in the normal course of business, the Partnership does not believe that it is a party to any litigation that will have a material adverse impact on its financial condition or results of operations. Except as described below and in Note 12 included herein, the Partnership is not aware of any significant legal or governmental proceedings against it, or contemplated to be brought against it. The Partnership maintains insurance policies with insurers in amounts and with coverage and deductibles as its general partner believes are reasonable and prudent. However, the Partnership can provide no assurance that this insurance will be adequate to protect it from all material expenses related to potential future claims or that these levels of insurance will be available in the future at economically acceptable prices.

Other

The Partnership recently 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 was impacted. The Partnership has notified the EPA. 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 relates 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 (“DEC”) 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 New York State Department of Environmental Conservation (“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 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 DEC comply with the CAA and applicable State air permitting requirements and that no material violation of law has occurred. The Partnership will contest the claims alleged in 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

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“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 at the Albany Terminal, particularly with respect to crude oil operations at the Albany Terminal. The October NOI revises the superseded and replaced 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, 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 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 they 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 and a decision from the Court is expected during the third quarter summer of 2016. At this time, all discovery and other litigation activity is stayed pending a decision by the Court on the motion to dismiss.

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, alleging certain violations of the National Pollutant Discharge Elimination System Permit (“NPDES Permit”) related to storm water discharges. The NON requires 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 is implementing modifications to the storm water management system at the Revere Terminal. The Partnership has determined that compliance with the NON and implementation of the plan will have no material impact on its operations.

The Partnership had a dispute with Lansing Ethanol Services, LLC (“Lansing”) for damages in excess of $12.0 million. The dispute involved Lansing’s failure to transfer RINs to the Partnership in connection with certain agreements for the purchase and sale of ethanol. The parties had agreed to arbitrate under the rules of the American Arbitration Association. The Partnership filed for arbitration on March 24, 2015 and the hearing was conducted in March 2016. A decision was rendered on June 10, 2016, which netted the Partnership $1.5 million. Neither party appealed the decision and the appeal period expired on July 14, 2016. The parties executed a Settlement Agreement and Mutual Release on August 2, 2016, and payment was made by Lansing and received by the Partnership on that date.

On May 16, 2014, the Partnership received a subpoena from the SEC requesting information for relevant time periods primarily relating to the Partnership’s accounting for RINs and the restatements of its consolidated financial statements as of and for the quarters ended March 31, 2013, June 30, 2013 and September 30, 2013. The Partnership has cooperated fully with the SEC and believes it has provided the SEC with all requested materials.

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

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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 was extended on May 17, 2016 and further extended on August 2, 2016. The Partnership does not believe that a 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 18. Changes in Accumulated Other Comprehensive Loss

The following table presents the changes in accumulated other comprehensive loss by component for the three and six months ended June 30, 2016 (in thousands):


	Pension
Three Months Ended June 30, 2016	Plan		Derivatives		Total
Balance at March 31, 2016	$	(4,368)	$	(3,397)	$	(7,765)
Other comprehensive income before reclassifications of gain (loss)		316		592		908
Amount of (loss) gain reclassified from accumulated other comprehensive income		(10)		—		(10)
Total comprehensive income		306		592		898
Balance at June 30, 2016	$	(4,062)	$	(2,805)	$	(6,867)

	Pension
Six Months Ended June 30, 2016	Plan		Derivatives		Total
Balance at December 31, 2015	$	(4,436)	$	(3,658)	$	(8,094)
Other comprehensive income before reclassifications of gain (loss)		393		853		1,246
Amount of (loss) gain reclassified from accumulated other comprehensive income		(19)		—		(19)
Total comprehensive income		374		853		1,227
Balance at June 30, 2016	$	(4,062)	$	(2,805)	$	(6,867)

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 19. New Accounting Standards

Accounting Standards or Updates Recently Adopted

In September 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2015-16, “Business Combinations: Simplifying the Accounting for Measurement-Period Adjustments.” This standard eliminates the requirement that an acquirer in a business combination account for measurement-period adjustments retrospectively. Instead, acquirers must recognize measurement-period adjustments during the period in which they determine the amounts, including the effect on earnings of any amounts they would have recorded in previous periods if the accounting had been completed at the acquisition date. The acquirer still must disclose the amounts and reasons for adjustments to the provisional amounts. The acquirer also must disclose, by line item, the amount of the adjustment reflected in the current-period income statement that would have been recognized in previous

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periods if the adjustment to provisional amounts had been recognized as of the acquisition date. Alternatively, an acquirer may present those amounts separately on the face of the income statement. The Partnership adopted this standard on January 1, 2016. The adoption of this standard did not have a material impact on the Partnership’s consolidated financial statements.

Accounting Standards or Updates Not Yet Effective

In May 2016, the FASB issued ASU 2016-12, “Revenue from Contracts with Customers: Narrow-Scope Improvements and Practical Expedients.” This standard amends ASU 2014-09, “Revenue from Contracts with Customers” (“ASU 2014-09”) discussed below. The amendments do not change the principles of ASU 2014-09, but clarify matters related to assessment of collectability criteria, presentation of sales and other taxes collected from customers, non-cash consideration, contract modifications at transition and completed contracts at transition. The effective date for this standard is the same as the effective date in ASU 2014-09. The Partnership is assessing the impact this standard will have on its consolidated financial statements.

In April 2016, the FASB issued ASU 2016-10, “Revenue from Contracts with Customers: Identifying Performance Obligations and Licensing.” This standard amends ASU 2014-09. The amendments in this standard clarify guidance related to identifying performance obligations and licensing implementation guidance provided in ASU 2014-09. The effective date and transition requirements for the amendments in this standard are the same as the effective date and transition requirements in ASU 2014-09. The Partnership is assessing the impact this standard will have on its 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 is assessing the impact this standard will have on its 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 adoption of this standard is not expected to have a material impact on the Partnership’s consolidated financial statements

In February 2016, the FASB issued ASU 2016-02, “Leases.” This standard amends the existing accounting standards for lease accounting, including requiring lessees to recognize most leases on their balance sheets and making targeted changes to lessor accounting. This standard is effective beginning in the first quarter of 2019. Early adoption of this standard is permitted. The standard requires a modified retrospective transition approach for all leases existing at, or entered into after, the date of initial application, with an option to use certain transition relief. 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

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adoption permitted. The adoption of this standard is not expected to 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. The new standard is effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years. The Partnership is assessing the impact this standard will have on its consolidated financial statements.

In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers,” that introduces a new five-step revenue recognition model in which an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This standard also requires disclosures sufficient to enable users to understand the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers, including qualitative and quantitative disclosures about contracts with customers, significant judgments and changes in judgments, and assets recognized from the costs to obtain or fulfill a contract. In July 2015, the FASB approved a one-year deferral of the effective date of the standard to fiscal periods beginning after December 15, 2017. The Partnership is evaluating the guidance to determine the impact it will have on its consolidated financial statements.

Note 20. Subsequent Events

Distribution—On July 27, 2016, 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, 2016 through June 30, 2016. On August 8, 2016, the Partnership will pay this cash distribution to its unitholders of record as of the close of business on August 12, 2016.

Sale of Gasoline Stations

On May 20, 2016, Drake Petroleum Company, Inc., an indirect wholly owned subsidiary of the Partnership, as seller, entered into a Purchase and Sale Agreement with Mirabito, as buyer, to sell to Mirabito 31 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 (the “Mirabito Disposition”). The Drake Sites are a portion of the sites that were acquired by the Partnership in connection with the acquisition of Warren January 7, 2015 (see Note 2). In connection with closing, the parties will enter into long-term supply contracts for branded and unbranded gasoline and other petroleum products. Closing of the Mirabito Disposition is subject to customary due diligence and is expected to occur in the third quarter of 2016. The Partnership expects to use the proceeds from the Mirabito Disposition to reduce indebtedness outstanding under its revolving credit facility.

Beginning in April 2016, the Partnership retained a real estate firm to coordinate the sale of non-strategic GDSO sites which are part of the Divesture Program. At June 30, 2016, the coordinated sale included 90 sites, all of which did not meet the criteria to be presented as held for sale (see Note 15). In July 2016, the criteria to be presented as held for sale was met for 32 of the 90 sites. The net book value of the assets at these 32 sites that will be sold or considered as held for sale in the third quarter of 2016 was $20.3 million at June 30, 2016. Assets held for sale are expected to be sold within the next 12 months.

Note 21. 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-

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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, 2016 and December 31, 2015, the Condensed Consolidating Statements of Operations for the three and six months ended June 30, 2016 and 2015 and the Condensed Consolidating Statements of Cash Flows for the six months ended June 30, 2016 and 2015 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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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Condensed Consolidating Balance Sheet

June 30, 2016

(In thousands)


	(Issuer)		Non-
	Guarantor		Guarantor
	Subsidiaries		Subsidiary		Eliminations		Consolidated
Assets
Current assets:
Cash and cash equivalents	$	8,029	$	565	$	—	$	8,594
Accounts receivable, net		357,960		182		—		358,142
Accounts receivable - affiliates		3,892		80		(110)		3,862
Inventories		443,994		—		—		443,994
Brokerage margin deposits		39,363		—		—		39,363
Derivative assets		29,590		—		—		29,590
Prepaid expenses and other current assets		67,288		390		—		67,678
Total current assets		950,116		1,217		(110)		951,223
Property and equipment, net		1,173,484		33,755		—		1,207,239
Intangible assets, net		70,200		—		—		70,200
Goodwill		349,306		86,063		—		435,369
Other assets		38,938		—		—		38,938
Total assets	$	2,582,044	$	121,035	$	(110)	$	2,702,969

Liabilities and partners' equity
Current liabilities:
Accounts payable	$	286,538	$	269	$	—	$	286,807
Accounts payable - affiliates		80		30		(110)		—
Working capital revolving credit facility - current portion		218,800		—		—		218,800
Environmental liabilities - current portion		5,337		—		—		5,337
Trustee taxes payable		96,364		—		—		96,364
Accrued expenses and other current liabilities		48,278		193		—		48,471
Derivative liabilities		24,088		—		—		24,088
Total current liabilities		679,485		492		(110)		679,867
Working capital revolving credit facility - less current portion		150,000		—		—		150,000
Revolving credit facility		213,400		—		—		213,400
Senior notes		657,866		—		—		657,866
Environmental liabilities - less current portion		65,144		—		—		65,144
Financing obligations		152,371		—		—		152,371
Deferred tax liabilities		79,738		—		—		79,738
Other long-term liabilities		56,551		—		—		56,551
Total liabilities		2,054,555		492		(110)		2,054,937

Partners' equity
Global Partners LP equity		527,489		78,190		—		605,679
Noncontrolling interest		—		42,353		—		42,353
Total partners' equity		527,489		120,543		—		648,032
Total liabilities and partners' equity	$	2,582,044	$	121,035	$	(110)	$	2,702,969

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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Condensed Consolidating Balance Sheet

December 31, 2015

(In thousands)


	(Issuer)		Non-
	Guarantor		Guarantor
	Subsidiaries		Subsidiary		Eliminations		Consolidated
Assets
Current assets:
Cash and cash equivalents	$	—	$	4,690	$	(3,574)	$	1,116
Accounts receivable, net		311,079		275		—		311,354
Accounts receivable - affiliates		2,745		746		(913)		2,578
Inventories		388,952		—		—		388,952
Brokerage margin deposits		31,327		—		—		31,327
Derivative assets		66,099		—		—		66,099
Prepaid expenses and other current assets		65,376		233		—		65,609
Total current assets		865,578		5,944		(4,487)		867,035
Property and equipment, net		1,203,251		39,432		—		1,242,683
Intangible assets, net		75,694		—		—		75,694
Goodwill		349,306		86,063		—		435,369
Other assets		42,894		—		—		42,894
Total assets	$	2,536,723	$	131,439	$	(4,487)	$	2,663,675

Liabilities and partners' equity
Current liabilities:
Cash overdraft	$	3,574	$	—	$	(3,574)	$	—
Accounts payable		303,242		539		—		303,781
Accounts payable - affiliates		746		167		(913)		—
Working capital revolving credit facility - current portion		98,100		—		—		98,100
Environmental liabilities - current portion		5,350		—		—		5,350
Trustee taxes payable		95,264		—		—		95,264
Accrued expenses and other current liabilities		59,742		586		—		60,328
Derivative liabilities		31,911		—		—		31,911
Total current liabilities		597,929		1,292		(4,487)		594,734
Working capital revolving credit facility - less current portion		150,000		—		—		150,000
Revolving credit facility		269,000		—		—		269,000
Senior notes		656,564		—		—		656,564
Environmental liabilities - less current portion		67,883		—		—		67,883
Financing obligations		89,790		—		—		89,790
Deferred tax liabilities		84,836		—		—		84,836
Other long-term liabilities		56,884		—		—		56,884
Total liabilities		1,972,886		1,292		(4,487)		1,969,691

Partners' equity
Global Partners LP equity		563,837		83,952		—		647,789
Noncontrolling interest		—		46,195		—		46,195
Total partners' equity		563,837		130,147		—		693,984
Total liabilities and partners' equity	$	2,536,723	$	131,439	$	(4,487)	$	2,663,675

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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 and impairment charges		2,530		—		—		2,530
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

Three Months Ended June 30, 2015

(In thousands)


	(Issuer)		Non-
	Guarantor		Guarantor
	Subsidiaries		Subsidiary		Eliminations		Consolidated

Sales	$	2,677,213	$	6,730	$	(3,855)	$	2,680,088
Cost of sales		2,537,435		2,320		(3,855)		2,535,900
Gross profit		139,778		4,410		—		144,188
Costs and operating expenses:
Selling, general and administrative expenses		44,760		631		—		45,391
Operating expenses		69,655		2,513		—		72,168
Amortization expense		2,793		277		—		3,070
Net loss on sale and disposition of assets and impairment charges		213		—		—		213
Total costs and operating expenses		117,421		3,421		—		120,842
Operating income (loss)		22,357		989		—		23,346
Interest expense		(16,451)		—		—		(16,451)
Income before income tax benefit		5,906		989		—		6,895
Income tax benefit		719		—		—		719
Net income		6,625		989		—		7,614
Net income attributable to noncontrolling interest		—		(396)		—		(396)
Net income attributable to Global Partners LP		6,625		593		—		7,218
Less: General partners' interest in net income, including incentive distribution rights		2,671		—		—		2,671
Limited partners' interest in net income	$	3,954	$	593	$	—	$	4,547

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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 and impairment charges		8,635		—		—		8,635
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 of Operations

Six Months Ended June 30, 2015

(In thousands)


	(Issuer)		Non-
	Guarantor		Guarantor
	Subsidiaries		Subsidiary		Eliminations		Consolidated

Sales	$	5,652,398	$	14,780	$	(7,974)	$	5,659,204
Cost of sales		5,349,908		4,524		(7,974)		5,346,458
Gross profit		302,490		10,256		—		312,746
Costs and operating expenses:
Selling, general and administrative expenses		92,787		1,390		—		94,177
Operating expenses		135,971		4,853		—		140,824
Amortization expense		5,379		3,032		—		8,411
Net loss on sale and disposition of assets and impairment charges		650		—		—		650
Total costs and operating expenses		234,787		9,275		—		244,062
Operating income (loss)		67,703		981		—		68,684
Interest expense		(30,409)		(5)		—		(30,414)
Income before income tax expense		37,294		976		—		38,270
Income tax expense		(247)		—		—		(247)
Net income		37,047		976		—		38,023
Net income attributable to noncontrolling interest		—		(390)		—		(390)
Net income attributable to Global Partners LP		37,047		586		—		37,633
Less: General partners' interest in net income, including incentive distribution rights		4,850		—		—		4,850
Limited partners' interest in net income	$	32,197	$	586	$	—	$	32,783

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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 payments on 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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GLOBAL PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Condensed Consolidating Statement Cash Flows

Six Months Ended June 30, 2015

(In thousands)


	(Issuer)		Non-
	Guarantor		Guarantor
	Subsidiaries		Subsidiary		Consolidated
Cash flows from operating activities
Net cash (used in) provided by operating activities	$	(65,254)	$	8,022	$	(57,232)

Cash flows from investing activities
Acquisitions		(561,757)		—		(561,757)
Capital expenditures		(30,809)		(2,354)		(33,163)
Proceeds from sale of property and equipment		1,251		—		1,251
Net cash used in investing activities		(591,315)		(2,354)		(593,669)

Cash flows from financing activities
Proceeds from issuance of common units, net		109,305		—		109,305
Net borrowings from working capital revolving credit facility		168,200		—		168,200
Net borrowings from revolving credit facility		134,200		—		134,200
Proceeds from senior notes, net of discount		295,125		—		295,125
Payments on line of credit		—		(700)		(700)
Repurchase of common units		(2,442)		—		(2,442)
Noncontrolling interest capital contribution		1,880		—		1,880
Distribution to noncontrolling interest		700		(4,300)		(3,600)
Distributions to partners		(45,118)		—		(45,118)
Net cash provided by (used in) financing activities		661,850		(5,000)		656,850

Cash and cash equivalents
Increase in cash and cash equivalents		5,281		668		5,949
Cash and cash equivalents at beginning of period		2,560		2,678		5,238
Cash and cash equivalents at end of period	$	7,841	$	3,346	$	11,187

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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 could 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 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 could result in a decrease in the utilization of these transportation assets, which could negatively impact our financial condition, results of operations and cash available for distribution to our unitholders. For example, during 2015 and to date 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 have experienced a reduction in our railcar movements but have 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, seasonality and supply, weather, logistics disruptions and other factors and uncertainties inherent in the transportation, storage, terminalling and marketing of crude oil and refined products.

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 us.

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.

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

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We are exposed to performance risk in our supply chain.

Our business is 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, 2015 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 domestic and Canadian crude oil, gasoline and gasoline blendstocks (such as ethanol), distillates (such as home heating oil, diesel and kerosene), residual oil, renewable fuels, natural gas and propane. We also receive revenue from convenience store sales and gasoline station rental income. We own, control or have access to one of the largest terminal networks of refined petroleum products and renewable fuels in Massachusetts, Maine, Connecticut, Vermont, New Hampshire, Rhode Island, New York, New Jersey and Pennsylvania (collectively, the “Northeast”). We 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 to the East and West Coasts. 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. As of June 30, 2016, we had a portfolio of 1,511 owned, leased and/or supplied gasoline stations, including 290 directly operated convenience stores, in the Northeast, Maryland and Virginia.

On January 7, 2015, we acquired, through one of our wholly owned subsidiaries, Global Montello Group Corp. (“GMG”), 100% of the equity interests in Warren Equities, Inc. (“Warren”) from The Warren Alpert Foundation. On January 14, 2015, through our wholly owned subsidiary, Global Companies LLC, we acquired the Revere terminal (the “Revere Terminal”) located in Boston Harbor in Revere, Massachusetts from Global Petroleum Corp. (“GPC”) and related entities. On June 1, 2015, through one of our wholly owned subsidiaries, Alliance Energy LLC, we acquired retail gasoline stations and dealer supply contracts from Capitol Petroleum Group (“Capitol”).

Collectively, we sold approximately $2.0 billion and $3.7 billion of refined petroleum products, renewable fuels, crude oil, natural gas and propane for the three and six months ended June 30, 2016, respectively. In addition, we had

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other revenues of approximately $0.1 billion and $0.2 billion for the three and six months ended June 30, 2016, respectively, primarily from convenience store sales at our directly operated stores and rental income from dealer leased or commission agent leased gasoline stations and from cobranding arrangements.

We base our pricing on spot prices, fixed prices or indexed prices and routinely use the New York Mercantile Exchange (“NYMEX”), Chicago Mercantile Exchange (“CME”), Intercontinental Exchange (“ICE”) or other counterparties to hedge the risk inherent in buying and selling commodities. Through the use of regulated exchanges or derivatives, we seek to maintain a position that is substantially balanced between purchased volumes and sales volumes or future delivery obligations.

Recent Transactions

Sale Leaseback Transaction—On June 29, 2016, we and our wholly owned subsidiaries Global Companies LLC (“Global Companies”), Global Montello Group Corp. (“GMG”) and Alliance Energy LLC (“Alliance”), and Alliance’s wholly owned subsidiary, Bursaw Oil LLC (“Bursaw”) 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 6 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, the stores were added through long-term leases.

Operating Segments

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

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. 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 on the East Coast. 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 Renewable Identification Numbers (“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 Renewable Volume Obligation (“RVO”). Our U.S. Environmental Protection Agency (“EPA”) obligations relative to renewable fuel reporting are largely limited to the foreign gasoline that we may choose to import.

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Gasoline Distribution and Station Operations

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, 2016, we had a portfolio of owned, leased and/or supplied gasoline stations, primarily in the Northeast, that consisted of the following:


Company operated		290
Commissioned agents		291
Lessee dealers		265
Contract dealers		665
Total		1,511

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 commission agent locations, we own the gasoline inventory, and we set the retail price of gasoline at the station and pay the commission agent a fee related to the gallons sold. We receive rental income from commission agent leased gasoline stations for the leasing of the convenience store premises, repair bays and other businesses that may be conducted by the commission 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 dealer‑leased gasoline stations and from cobranding arrangements. We also supply gasoline to independent contract dealers under agreements with the operators at these locations. Additionally, we have contractual relationships with distributors in certain New England states, pursuant to which we 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, bunker fuel and natural gas. 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.

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.

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Outlook

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

Our business is influenced by the overall markets for refined petroleum products, renewable fuels, crude oil, natural gas 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, natural gas 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 could adversely affect the economics of domestic crude oil production which, in turn, could have an adverse effect on our crude oil logistics activities and sales. A significant decrease in differentials could also have an adverse effect on our crude oil logistics activities and sales. In addition, a prolonged decline in crude oil prices and differentials may become an indicator of the potential impairment of our long-lived assets used at our terminals in North Dakota.

On January 28, 2016, we announced a reduction in the quarterly distribution for the fourth quarter of 2015 on all outstanding common units to $0.4625. This distribution represented a decrease of 33.7% from the distribution of $0.6975 per unit paid in November 2015 and a decrease of 30.5% from the distribution of $0.6650 per unit paid in February 2015. The reduction in the distribution primarily reflected the continuing weakness in the crude oil market. The significant decline in the price of crude oil and tight crude oil differentials negatively impacted our fiscal 2015 and to date 2016 results. On April 26, 2016 and July 27, 2016, we announced that we would maintain the quarterly distribution of $0.4625 per unit for the first and second quarters of 2016, respectively.

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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 on our ability to make accretive acquisitions and/or accretive development projects. We may be unable to execute such accretive transactions for a number of reasons, including, but not limited to, the following: (1) we are unable to identify attractive transaction candidates or negotiate acceptable terms; (2) we are unable to obtain financing for such transactions on economically acceptable terms; or (3) we are outbid by competitors. In addition, we may consummate transactions that at the time of consummation we believe will be accretive but that ultimately may not be accretive. If any of these events were to occur, our future growth and ability to increase 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 the railroads and their employees and labor renegotiations, including strikes, lockouts or a work stoppage, shortage of railcars, mechanical difficulties or bottlenecks and disruptions in railroad logistics could also disrupt rail service. These events could result in service disruptions and increased cost which could also adversely affect our financial condition, results of operations and cash available for distribution to our unitholders. Other disruptions, such as those due to an act of terrorism or war, could also adversely affect our business.

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 these transportation assets, which could negatively impact our financial condition, results of operations and cash available for distribution to our unitholders. For example, during 2015 and to date in 2016, we have experienced adverse market conditions in crude oil caused by an over-supplied and crude oil market which resulted in tighter price differentials, and we have experienced a reduction in our railcar movements but remained obligated to pay the applicable fixed charges for railcar leases.

Our gasoline financial results 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.

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

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

Changes in government usage mandates and tax credits could adversely affect the availability and pricing of ethanol, which could negatively impact our sales. Future demand for ethanol will be largely dependent upon the economic incentives to blend based upon the relative value of gasoline and ethanol, taking into consideration the EPA’s regulations on the Renewable Fuels Standard (“RFS”) program and oxygenate blending requirements. A reduction or waiver of the RFS mandate or oxygenate blending requirements could adversely affect the availability and pricing of ethanol, which in turn could adversely affect our future gasoline and ethanol sales. In addition, changes in blending requirements could affect the price of RINs which could impact the magnitude of the mark-to-market liability recorded for the deficiency, if any, in our RIN position relative to our RVO at a point in time.

New, stricter environmental laws and other industry-related regulations could significantly impact our operations and/or increase our costs, which could adversely affect our results of operations and financial condition. Our operations are subject to federal, state and local laws and regulations regulating, among other matters, logistics activities, product quality specifications and other environmental matters. The trend in environmental regulation is towards more restrictions and limitations on activities that may affect the environment over time. Our business may be adversely affected by increased costs and liabilities resulting from such stricter laws and regulations. We try to anticipate future regulatory requirements that might be imposed and plan accordingly to remain in compliance with changing environmental laws and regulations and to minimize the costs of such compliance. The federal government recently finalized a rule including new design and construction requirements for railroad tank cars that are used to transport crude oil and ethanol. The establishment of more stringent design or construction 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, some environmental interest groups have commenced efforts to seek to use state and local laws to restrict the types of railroad tanks cars that can be used to deliver crude oil and ethanol to bulk storage terminals. Were such state and local 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.

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Results of Operations

Evaluating Our Results of Operations

Our management uses a variety of financial and operational measurements to analyze our performance. These measurements include: (1) 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.

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, 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 the gain or loss on the sale and disposition of assets and 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

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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 means our net income plus depreciation and amortization minus maintenance capital expenditures, as well as adjustments to eliminate items approved by the audit committee of the board of directors of our general partner that are extraordinary or non-recurring in nature and that would otherwise increase distributable cash flow.

Specifically, this financial measure indicates to investors whether or not we have generated sufficient earnings on a current or historic level that can sustain or support an increase in our quarterly cash distribution. Distributable cash flow is a quantitative standard used by the investment community with respect to publicly traded partnerships. Distributable cash flow should not be considered as an alternative to net income, operating income, cash flow from operations, or any other measure of financial performance presented in accordance with GAAP. In addition, our distributable cash flow may not be comparable to distributable cash flow or similarly titled measures of other companies.

Selling, General and Administrative Expenses

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

Operating Expenses

Operating expenses are costs associated with the operation of the terminals, transload facilities and gasoline stations used in our business. Lease payments and storage expenses, maintenance and repair, utilities, 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,
	2016		2015		2016		2015
Net (loss) income attributable to Global Partners LP	$	(7,310)	$	7,218	$	(14,334)	$	37,633
EBITDA (1)	$	41,301	$	48,710	$	83,873	$	120,551
Adjusted EBITDA (1)	$	43,831	$	48,923	$	92,508	$	121,201
Distributable cash flow (2)(3)	$	14,248	$	26,172	$	30,629	$	79,882
Wholesale Segment:
Volume (gallons)		758,179		825,473		1,573,164		1,978,428
Sales
Gasoline and gasoline blendstocks	$	594,411	$	718,971	$	937,140	$	1,495,114
Crude oil (4)		160,595		363,880		309,097		615,990
Other oils and related products (5)		318,123		401,083		737,132		1,344,776
Total	$	1,073,129	$	1,483,934	$	1,983,369	$	3,455,880
Product margin
Gasoline and gasoline blendstocks	$	26,612	$	17,708	$	42,974	$	47,537
Crude oil (4)		(9,648)		36,828		(12,021)		52,085
Other oils and related products (5)		15,804		6,405		41,053		41,412
Total	$	32,768	$	60,941	$	72,006	$	141,034
Gasoline Distribution and Station Operations Segment:
Volume (gallons)		403,573		376,866		767,420		718,324
Sales
Gasoline	$	815,634	$	906,511	$	1,431,737	$	1,603,845
Station operations (6)		101,058		98,417		186,243		181,492
Total	$	916,692	$	1,004,928	$	1,617,980	$	1,785,337
Product margin
Gasoline	$	66,999	$	53,209	$	132,386	$	114,908
Station operations (6)		49,267		45,066		92,192		81,789
Total	$	116,266	$	98,275	$	224,578	$	196,697
Commercial Segment:
Volume (gallons)		115,275		106,996		243,000		233,378
Sales	$	156,378	$	191,226	$	295,662	$	417,987
Product margin	$	5,480	$	7,023	$	12,390	$	18,581
Combined sales and product margin:
Sales	$	2,146,199	$	2,680,088	$	3,897,011	$	5,659,204
Product margin (7)	$	154,514	$	166,239	$	308,974	$	356,312
Depreciation allocated to cost of sales		(25,172)		(22,051)		(49,573)		(43,566)
Combined gross profit	$	129,342	$	144,188	$	259,401	$	312,746

GDSO portfolio as of June 30, 2016 and 2015:		2016		2015
Company operated		290		286
Commissioned agents		291		282
Lessee dealers		265		296
Contract dealers		665		673
Total GDSO portfolio		1,511		1,537

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	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2016			2015			2016			2015
Weather conditions:
Normal heating degree days		784			784			3,685			3,654
Actual heating degree days		786			737			3,346			4,193
Variance from normal heating degree days		0.3	%		(6)	%		(9)	%		15	%
Variance from prior period actual heating degree days		7	%		(0.3)	%		(20)	%		8	%

(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.” 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 and impairment charges of $2.5 million and $0.2 million for the three months ended June 30, 2016 and 2015, respectively, and $8.6 million and $0.6 million for the six months ended June 30, 2016 and 2015, respectively. Excluding the net loss on sale and disposition of assets and impairment charges, distributable cash flow would have been $16.8 million and $26.4 million for the three months ended June 30, 2016 and 2015, respectively, and $39.3 million and $80.5 million for the six months ended June 30, 2016 and 2015, respectively.

(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 primarily consist of convenience stores sales and rental income.

(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.

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,
	2016		2015		2016		2015
Reconciliation of net (loss) income to EBITDA and Adjusted EBITDA:
Net (loss) income	$	(8,543)	$	7,614	$	(16,378)	$	38,023
Net loss (income) attributable to noncontrolling interest		1,233		(396)		2,044		(390)
Net (loss) income attributable to Global Partners LP		(7,310)		7,218		(14,334)		37,633
Depreciation and amortization, excluding the impact of noncontrolling interest		28,146		25,760		55,682		52,259
Interest expense, excluding the impact of noncontrolling interest		21,015		16,451		43,995		30,412
Income tax (benefit) expense		(550)		(719)		(1,470)		247
EBITDA		41,301		48,710		83,873		120,551
Net loss on sale and disposition of assets and impairment charges		2,530		213		8,635		650
Adjusted EBITDA	$	43,831	$	48,923	$	92,508	$	121,201

Reconciliation of net cash (used in) provided by operating activities to EBITDA and Adjusted EBITDA:
Net cash (used in) provided by operating activities	$	(6,467)	$	56,683	$	(59,983)	$	(57,232)
Net changes in operating assets and liabilities and certain non-cash items		27,204		(22,301)		101,554		150,495
Net cash from operating activities and changes in operating assets and liabilities attributable to noncontrolling interest		99		(1,404)		(223)		(3,371)
Interest expense, excluding the impact of noncontrolling interest		21,015		16,451		43,995		30,412
Income tax (benefit) expense		(550)		(719)		(1,470)		247
EBITDA		41,301		48,710		83,873		120,551
Net loss on sale and disposition of assets and impairment charges		2,530		213		8,635		650
Adjusted EBITDA	$	43,831	$	48,923	$	92,508	$	121,201

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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,
	2016		2015		2016		2015
Reconciliation of net (loss) income to distributable cash flow:
Net (loss) income	$	(8,543)	$	7,614	$	(16,378)	$	38,023
Net loss (income) attributable to noncontrolling interest		1,233		(396)		2,044		(390)
Net (loss) income attributable to Global Partners LP		(7,310)		7,218		(14,334)		37,633
Depreciation and amortization, excluding the impact of noncontrolling interest		28,146		25,760		55,682		52,259
Amortization of deferred financing fees and senior notes discount		1,866		1,700		3,638		3,338
Amortization of routine bank refinancing fees		(1,168)		(1,126)		(2,245)		(2,247)
Maintenance capital expenditures, excluding the impact of noncontrolling interest		(7,286)		(7,380)		(12,112)		(11,101)
Distributable cash flow (1)	$	14,248	$	26,172	$	30,629	$	79,882

Reconciliation of net cash (used in) provided by operating activities to distributable cash flow:
Net cash (used in) provided by operating activities	$	(6,467)	$	56,683	$	(59,983)	$	(57,232)
Net changes in operating assets and liabilities and certain non-cash items		27,204		(22,301)		101,554		150,495
Net cash from operating activities and changes in operating assets and liabilities attributable to noncontrolling interest		99		(1,404)		(223)		(3,371)
Amortization of deferred financing fees and senior notes discount		1,866		1,700		3,638		3,338
Amortization of routine bank refinancing fees		(1,168)		(1,126)		(2,245)		(2,247)
Maintenance capital expenditures, excluding the impact of noncontrolling interest		(7,286)		(7,380)		(12,112)		(11,101)
Distributable cash flow (1)	$	14,248	$	26,172	$	30,629	$	79,882

(1)

Includes a net loss on sale and disposition of assets and impairment charges of $2.5 million and $0.2 million for the three months ended June 30, 2016 and 2015, respectively, and $8.6 million and $0.6 million for the six months ended June 30, 2016 and 2015, respectively. Excluding the net loss on sale and disposition of assets and impairment charges, distributable cash flow would have been $16.8 million and $26.4 million for the three months ended June 30, 2016 and 2015, respectively, and $39.3 million and $80.5 million for the six months ended June 30, 2016 and 2015, respectively.

Consolidated Sales

Our total sales were $2.2 billion and $2.7 billion for the three months ended June 30, 2016 and 2015, respectively, a decrease of $0.5 billion, or 19%, due primarily to a decrease in prices. Our aggregate volume of product sold was approximately 1.3 billion gallons for each of the three months ended June 30, 2016 and 2015. During the second quarter of 2016, our volume sold increased by 27 million gallons in our GDSO segment, primarily due to the Capitol acquisition and to the addition of 22 leased sites in Western Massachusetts in April 2016, and by 8 million gallons in our Commercial segment and decreased by 67 million in our Wholesale segment, primarily in crude oil.

Our total sales were $3.9 billion and $5.7 billion for the six months ended June 30, 2016 and 2015, respectively, a decrease of $1.8 billion, or 31%, primarily due to a decrease in prices and to a decline in volume sold. Our aggregate volume of product sold was 2.6 billion gallons and 2.9 billion gallons for the six months ended June 30, 2016 and 2015, respectively, a decrease of approximately 0.3 million gallons, or 10%. The decrease in volume sold includes a decrease of 405 million gallons in our Wholesale segment, primarily in gasoline and gasoline blendstocks, but also in distillates and crude oil. The decrease in volume sold was offset by increases of 49 million gallons in our GDSO segment, largely due to the Capitol acquisition and 10 million gallons in our Commercial segment.

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Gross Profit

Our gross profit was $129.3 million and $144.2 million for the three months ended June 30, 2016 and 2015, respectively, a decrease of $14.9 million, or 10%, primarily due to less activity in crude oil caused by tighter differentials, partially offset by an increase in our GDSO segment due to improved gasoline margins as well as the Capitol acquisition, and to more favorable market conditions in our Wholesale segment in gasoline and distillates.

Our gross profit was $259.4 million and $312.7 million for the six months ended June 30, 2016 and 2015, respectively, a decrease of $53.3 million, or 17%, primarily due to less activity in crude oil caused by tighter differentials, partially offset by an increase in our GDSO segment due to the Capitol acquisition and improved gasoline margins.

Results for Wholesale Segment

Gasoline and Gasoline Blendstocks. Sales from wholesale gasoline and gasoline blendstocks were $0.6 billion and $0.7 billion for the three months ended June 30, 2016 and 2015, respectively. The decrease of approximately $0.1 billion, or 14%, was primarily due to a decrease in price. Our gasoline and gasoline blendstocks product margin was $26.6 million and $17.7 million for the three months ended June 30, 2016 and 2015, an increase of $8.9 million, or 50%, primarily due to more favorable market conditions in wholesale gasoline and gasoline blendstocks.

Sales from wholesale gasoline and gasoline blendstocks were $0.9 billion and $1.5 billion for the six months ended June 30, 2016 and 2015, respectively. The decrease of approximately $0.6 billion, or 37%, was primarily due to a decrease in gasoline prices and in volume sold. The decrease in volume sold was due, in part, to an elective change in supply logistics for a particular gasoline customer in early 2015, which did not have a material impact on our product margin for the first six months of 2016. Our gasoline and gasoline blendstocks product margin was $43.0 million and $47.5 million for the six months ended June 30, 2016 and 2015, a decrease of $4.5 million, or 9%, primarily due to favorable market conditions in wholesale gasoline in the first quarter of 2015 that were not present in the first quarter of 2016, partially offset by more favorable market conditions in both wholesale gasoline and gasoline blendstocks during the second quarter of 2016.

Crude Oil. Crude oil sales and logistics revenues were $0.2 billion and $0.4 billion for the three months ended June 30, 2016 and 2015, respectively, a decrease of $0.2 billion, or 50%, due to a decline in crude oil prices and a decrease in volume. We had a negative product margin from crude oil of $9.6 million for the second quarter of 2016 compared to a product margin of $36.8 million for the second quarter of 2015, a decrease of approximately $46.5 million, or 126%, primarily due to the result of tighter crude oil differentials as mid-continent crude oil did not discount sufficiently to make rail transport to the East Coast competitive with imports. In the second quarter of 2016, our product margin was negatively impacted by the absence of logistics nominations from one particular contract customer. Due to the absence of second quarter 2016 nominations by that customer, we expect additional revenue of approximately $8.0 million related to the take-or-pay nature of the contract by December 31, 2016. Any revenue from this contract in the fourth quarter of 2016 will reflect amounts owed to us for the lack of logistics nominations during the year. Our crude oil product margin for the second quarters of 2016 and 2015 was negatively impacted by fixed costs which included contracted barges, pipeline commitments and railcar leases. The primary fixed cost allocated to crude oil in the second quarter of 2016 was our railcar lease expense of $11.5 million as compared to $12.2 million in the second quarter of 2015. The majority of these cars were in storage as of June 30, 2016.

Crude oil sales and logistics revenues were $0.3 billion and $0.6 billion for the six months ended June 30, 2016 and 2015, respectively, a decrease of $0.3 billion, or 50%, due primarily to a decline in crude oil prices and a decrease in volume. We had a negative product margin from crude oil of $12.0 million for the first six months of 2016 compared to a product margin of $52.1 million for the same period in 2015, a decrease of $64.1 million, or 123%, primarily due to the result of tighter crude oil differentials as mid-continent crude oil did not discount sufficiently to make rail transport to the East Coast competitive with imports. Our product margin for the first six months of 2016 was negatively impacted by the absence of logistics nominations from one particular contract customer, specifically in the second quarter. Due to the absence of second quarter 2016 nominations by that customer, we expect additional revenue of approximately $8.0 million related to the take-or-pay nature of contract by December 31, 2016. Any revenue from this contract in the

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fourth quarter of 2016 will reflect amounts owed to us for the lack of logistics nominations during the year. Our crude oil product margin for the first six months of 2016 and 2015 was negatively impacted by fixed costs which included contracted barges, pipeline commitments and railcar leases. The primary fixed cost allocated to crude oil in the first six months of 2016 was our railcar lease expense of $23.2 million as compared to $23.8 million in the first six months of 2015. The future lease expense for these railcars is estimated at $21.8 million for the remainder of 2016, and $45.0 million and $39.0 million in 2017 and 2018, respectively, with a significant reduction to approximately $20.0 million in 2019 after which the leases expire. These cars can be used for crude oil, ethanol or other products. For the six months ended June 30, 2015, our crude oil product margin was also negatively impacted by a $5.0 million reserve related to a customer dispute in the first quarter of 2015.

Other Oils and Related Products. Sales from other oils and related products (primarily distillates, residual oil and propane) were $0.3 billion and $0.4 billion for the three months ended June 30, 2016 and 2015, respectively, a decrease of $0.1 billion, or 25%, due to a decline in prices. Our product margin from other oils and related products was $15.8 million and $6.4 million for the three months ended June 30, 2016 and 2015, respectively, an increase of $9.4 million, or 147%, primarily due to more favorable market conditions in distillates and improved margins in propane.

Sales from other oils and related products were $0.7 billion and $1.3 billion for the six months ended June 30, 2016 and 2015, respectively, a decrease of $0.6 billion, or 46%, due to a decrease in prices and a decline in volume sold. Our product margin from other oils and related products was $41.0 million and $41.4 million for the six months ended June 30, 2016 and 2015, respectively, a decrease of $0.4 million, or 1%, primarily due to warmer weather during the first quarter of 2016 when temperatures were 12% warmer than normal and 26% warmer than the first quarter of 2015, offset by more favorable market conditions in distillates and improved margins in propane.

Results for Gasoline Distribution and Station Operations Segment

Gasoline Distribution. Sales from gasoline distribution were $0.8 billion and $0.9 billion for the three months ended June 30, 2016 and 2015, respectively, a decrease of $0.1 billion, or 10%. Our sales benefitted due to the Capitol acquisition but were negatively impacted by lower prices during the quarter. Our product margin from gasoline distribution was $67.0 million and $53.2 million for the three months ended June 30, 2016 and 2015, respectively, an increase of $13.8 million, or 26%, due to improved gasoline margins, the Capitol acquisition, expansion of our leased portfolio, including the addition of 22 leased sites in April 2016, and the opening for business of certain raze and rebuild projects and new-to-industry sites. Our product margin in gasoline distribution for the second quarters of 2016 and 2015 was negatively impacted by rising gasoline prices, particularly during April and May.

Sales from gasoline distribution were $1.4 billion and $1.6 billion for the six months ended June 30, 2016 and 2015, respectively, a decrease of $0.2 billion, or 12%, due to lower prices during the period, offset by an increase in volume sold primarily due to the acquisition of Capitol. Our product margin from gasoline distribution was $132.4 million and $114.9 million for the six months ended June 30, 2016 and 2015, respectively, an increase of $17.5 million, or 15%, primarily due to the Capitol acquisition and to improved gasoline margins during the second quarter of 2016. Our product margin in gasoline distribution for the first six months of 2016 and 2015 was negatively impacted by rising gasoline prices during these periods.

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) 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, 2016 and 2015. Our product margin from station operations was $49.3 million and $45.1 million for the three months ended June 30, 2016 and 2015, respectively, an increase of $4.2 million, or 9%. The increases in sales and product margin for the three months ended June 30, 2016 were largely due to the Capitol acquisition and to an additional 22 leased sites in April 2016.

Sales from our station operations were approximately $0.2 billion for each of the six months ended June 30, 2016 and 2015. Our product margin from station operations was $92.2 million and $81.8 million for the six months ended

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June 30, 2016 and 2015, respectively, an increase of $10.4 million, or 13%. The increases in sales and product margin for the six months ended June 30, 2016 were largely due to the Capitol acquisition.

Results for Commercial Segment

Our commercial sales were approximately $0.2 billion for each of the three months ended June 30, 2016 and 2015. Our commercial product margin was $5.5 million and $7.0 million for the three months ended June 30, 2016 and 2015, respectively, a decrease of $1.5 million, or 21%, primarily due to a decrease in bunkering activity.

Sales from our commercial sales were $0.3 billion and $0.4 billion for the six months ended June 30, 2016 and 2015, respectively, a decrease of $0.1 billion, or 25%, due to a decrease in prices. Our commercial product margin was $12.4 million and $18.6 million for the six months ended June 30, 2016 and 2015, respectively, a decrease of $6.2 million, or 33%, primarily due to a decrease in bunkering activity during the second quarter and to warmer weather during the first quarter of 2016 compared to the same period in 2015 which negatively impacted our weather-sensitive products.

Selling, General and Administrative Expenses

SG&A expenses were $36.6 million and $45.4 million for the three months ended June 30, 2016 and 2015, respectively, a decrease of approximately $8.8 million, or 19%, including decreases of $3.0 million in due diligence expenses related to potential acquisitions and growth opportunities and professional fees and $2.7 million in accrued incentive compensation. The decrease in SG&A expenses also reflects $4.2 million in acquisition costs in connection with the Capitol and Warren acquisitions in 2015. The decrease in SG&A expenses was offset by $0.9 million in severance charges incurred related to a reduction in our workforce and an increase of $0.2 million in various other SG&A expenses.

SG&A expenses were $71.6 million and $94.2 million for the six months ended June 30, 2016 and 2015, respectively, a decrease of approximately $22.6 million, or 24%, including decreases of $7.8 million in accrued incentive compensation, $4.8 million in due diligence expenses related to potential acquisitions and growth opportunities and professional fees and $1.4 million in various other SG&A expenses. The decrease in SG&A expenses also reflects $7.7 million in acquisition costs and restructuring charges in connection with the Warren acquisition and $3.1 million in acquisition costs in connection with the Capitol acquisition in 2015. The decrease in SG&A expenses was offset by $2.2 million in severance charges incurred related to a reduction in our workforce.

Operating Expenses

Operating expenses were $75.9 million and $72.1 million for the three months ended June 30, 2016 and 2015, respectively, an increase of approximately $3.7 million, or 5%. Operating expenses increased by $5.1 million associated with our GDSO segment, largely due to the Capitol acquisition, primarily in rent expense, maintenance and repairs and property taxes and to the addition of 22 leased sites in April 2016. Operating expenses at our Oregon facility increased by $1.6 million, due to $2.2 million in costs associated with cleaning tanks and related infrastructure in order to convert the facility to ethanol transloading, offset by a decrease of $0.6 million in various operating expenses. The increase in operating expenses was offset by decreases of $1.5 million in operating costs at our Basin Transload facilities in North Dakota and $1.4 million in various operating expenses associated with our terminal operations.

Operating expenses were $148.1 million and $140.8 million for the six months ended June 30, 2016 and 2015, respectively, an increase of $7.3 million, or 5%. Operating expenses increased by $9.0 million associated with our GDSO segment, largely due to the Capitol acquisition, primarily in rent expense, maintenance and repairs and property taxes. Operating expenses at our Oregon facility increased by $2.6 million, due to $3.8 million in costs associated with cleaning tanks and related infrastructure in order to convert the facility to ethanol transloading, offset by a decrease of $1.2 million in various operating expenses. In addition, we incurred $0.1 million in severance charges related to a reduction in our workforce. The increase in operating expenses was offset by decreases of $2.2 million in operating costs at our Basin Transload facilities in North Dakota and $2.2 million in various operating expenses associated with our terminal operations.

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Amortization Expense

Amortization expense related to our intangible assets was $2.4 million and $3.1 million for the three months ended June 30, 2016 and 2015, respectively, a decrease of $0.7 million, or 23%. The decrease was primarily due to intangibles that became fully amortized during the second quarter of 2015.

Amortization expense related to our intangible assets was $4.9 million and $8.4 million for the six months ended June 30, 2016 and 2015, respectively, a decrease of $3.5 million, or 42%. The decrease was primarily due to intangibles that became fully amortized during the second quarter of 2015, partially offset by the intangible assets acquired in the Capitol acquisition.

Net Loss on Sale and Disposition of Assets and Impairment Charges

Net loss on sale and disposition of assets and impairment charges were $2.5 million and $0.2 million for the three months ended June 30, 2016 and 2015, respectively. For the three months ended June 30, 2016, we recorded impairment charges of $2.2 million associated with (i) the long-lived assets used in supplying compressed natural gas, (ii) the long-lived assets of one discrete GDSO site, and (iii) our assets classified as held for sale, and we recognized a $0.3 million net loss on the sale of gasoline stations and the sale and disposition of other assets. For the three months ended June 30, 2015, we did not record any impairment charges and recognized a $0.2 million net loss on the sale of gasoline stations and the sale and disposition of other assets. See Note 15 of Notes to Consolidated Financial Statements for additional information.

Net loss on sale and disposition of assets and impairment charges were $8.6 million and $0.6 million for the six months ended June 30, 2016 and 2015, respectively. For the six months ended June 30, 2016, we recorded impairment charges of $7.8 million associated with (i) our assets classified as held for sale, ii) the long-lived assets used in supplying compressed natural gas, and (iii) the long-lived assets of one discrete GDSO site, and we recognized a $0.8 million net loss on the sale of gasoline stations and the sale and disposition of other assets. For the six months ended June 30, 2015, we did not record any impairment charges and recognized a $0.6 million net loss on the sale of gasoline stations and the sale and disposition of other assets. See Note 15 of Notes to Consolidated Financial Statements for additional information.

Interest Expense

Interest expense was $21.0 million and $16.4 million for the three months ended June 30, 2016 and 2015, respectively, an increase of $4.6 million, or 28%. The increase was due primarily to (i) increased interest related to the 7.00% Notes; (ii) additional borrowings related to the Capitol acquisition; and (iii) $1.6 million for the second quarter of 2016 associated with the financing obligation recognized in connection with the acquisition of Capitol.

Interest expense was $44.0 million and $30.4 million for the six months ended June 30, 2016 and 2015, respectively, an increase of $13.6 million, or 45%. The increase was due primarily to (i) increased interest related to the 7.00% Notes (ii) additional borrowings related to the Capitol acquisition; (iii) $4.0 million for the first six months of 2016 associated with the financing obligation recognized in connection with the acquisition of Capitol; and (iv) $1.8 million associated with the write-off of a portion of our deferred financing fees associated with the elected reduction in our working capital revolving credit facility and our revolving credit facility. Please see Note 6 of Notes to Consolidated Financial Statements for additional information on the 7.00% Notes, the financing obligation and the write-off of deferred financing fees.

Income Tax Benefit (Expense)

Income tax benefit of $0.6 million and $0.7 million for the three months ended June 30, 2016 and 2015, respectively, and income tax benefit (expense) of $1.5 million and ($0.2 million) for the six months ended June 30, 2016 and 2015, respectively, reflect the operating results of our wholly owned subsidiary, GMG, which is a taxable entity for federal and state income tax purposes.

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Net (Loss) Income Attributable to Noncontrolling Interest

In February 2013, we acquired a 60% membership interest in Basin Transload. The net (loss) income attributable to noncontrolling interest of ($1.2 million) and $0.4 million the for three months ended June 30, 2016 and 2015, respectively, and ($2.0 million) and $0.4 million for the six months ended June 30, 2016 and 2015, respectively, represents the 40% noncontrolling ownership of the net income 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.

Working capital was $271.4 million and $272.3 million at June 30, 2016 and December 31, 2015, respectively, a decrease of $0.9 million. Increases to working capital primarily include (i) increases of $55.0 million and $46.8 million in inventories and accounts receivable, respectively, largely due to higher prices; (ii) a $17.0 million reduction in accounts payable as we exited the heating season and also because of lower crude oil volume; and (iii) an $11.9 million decrease in accrued expenses and other current liabilities, in part due to an $8.3 million reduction in incentive compensation for a total increase of $130.7 million. The increase was offset by an increase of $120.7 million 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 6 of Notes to Consolidated Financial Statements).

Cash Distributions

During 2016, 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 16, 2016 (1)	$	15.8 million	Fourth quarter 2015
May 16, 2016	$	15.8 million	First quarter 2016

(1)

On July 27, 2016, 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, 2016 through June 30, 2016 to our unitholders of record as of the close of business on August 8, 2016. We expect to pay the cash distribution of approximately $15.8 million on August 12, 2016.

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Contractual Obligations

We have contractual obligations that are required to be settled in cash. The amounts of our contractual obligations at June 30, 2016 were as follows (in thousands):


	Payments due by period
	Remainder of								2020 and
Contractual Obligations	2016		2017		2018		2019		Thereafter		Total
Credit facility obligations (1)	$	229,503	$	190,607	$	190,607	$	—	$	—	$	610,717
Senior notes obligations (2)		22,219		44,438		44,438		44,438		807,094		962,627
Operating lease obligations (3)		79,056		140,438		113,826		68,222		179,348		580,890
Capital lease obligations		88		201		97		—		—		386
Other long-term liabilities (4)		14,275		26,344		24,659		32,653		98,445		196,376
Financing obligations (5)		6,970		14,099		14,327		14,561		158,509		208,466
Total	$	352,111	$	416,127	$	387,954	$	159,874	$	1,243,396	$	2,559,462

(1)

Includes principal and interest on our working capital revolving credit facility and our revolving credit facility at June 30, 2016 and assumes a ratable payment through the expiration date. Our credit agreement has a contractual maturity of April 30, 2018 and no principal payments are required prior to that date. However, we repay amounts outstanding and reborrow funds based on our working capital requirements. Therefore, the current portion of the working capital revolving credit facility included in the accompanying balance sheets is the amount we expect to pay down during the course of the year, and the long-term portion of the working capital revolving credit facility is the amount we expect to be outstanding during the entire year. Please read “—Credit Agreement” for more information on our working capital revolving credit facility.

(2)

Includes principal and interest on the 6.25% Notes and the 7.00% 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 includes 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 will be classified as interest expense on the respective financing obligation and the pay-down of the related financing obligation. See Note 6 of Notes to Consolidated Financial Statement for additional information.

Capital Expenditures

Our operations require investments to expand, upgrade and enhance existing operations and to meet environmental and operations regulations. We categorize our capital requirements as either maintenance capital expenditures or expansion capital expenditures. Maintenance capital expenditures represent capital expenditures to repair or replace partially or fully depreciated assets to maintain the operating capacity of, or revenues generated by, existing assets and extend their useful lives. Maintenance capital expenditures also include expenditures required to maintain equipment reliability, tankage and pipeline integrity and safety and to address certain environmental regulations. We anticipate that maintenance capital expenditures will be funded with cash generated by operations. We had approximately $12.1 million and $11.2 million in maintenance capital expenditures for the six months ended June 30, 2016 and 2015, respectively, which are included in capital expenditures in the accompanying consolidated statements of cash flows and largely consisted of investments in our gasoline stations. Specifically, approximately $8.7 million and $8.2 million for the six months ended June 30, 2016 and 2015, 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 increasing, for example, rail capacity, dock capacity and tankage, diversifying product availability, raze and rebuilds, new-to-industry gasoline stations and convenience stores, storage flexibility at various terminals and by adding terminals. We have the ability to fund our expansion capital expenditures through cash from operations or our credit agreement or by issuing debt securities or

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additional equity. We had approximately $26.7 million and $453.1 million in expansion capital expenditures for the six months ended June 30, 2016 and 2015, respectively, which are included in capital expenditures in the accompanying consolidated statements of cash flows.

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.

For the six months ended June 30, 2015, the $453.1 million in expansion capital expenditures consisted of $431.1 million in property and equipment associated with the acquisitions of Warren, the Revere Terminal and Capitol. In addition, we had $22.0 million in expansion capital expenditures which consisted of (i) $13.3 million in new site development, rebuilds, expansion and improvements at retail gasoline stations, (ii) $4.9 million in costs associated with our crude oil activities, including, in part, tank construction projects, rail expansion and improvement costs and equipment upgrades and (iii) $3.8 million in other expansion capital expenditures including, in part, investments in information technology and computer and equipment upgrades at various terminals. Certain of the $4.9 million for the six months ended June 30, 2015 in costs associated with our crude oil activities include expenditures related to our Beulah, North Dakota facility, 60% of which was funded by us and 40% was funded by the noncontrolling interest at Basin Transload. These costs are reported in the accompanying consolidated statements of cash flows as we concluded that we control the entity based on an evaluation of the outstanding voting interests.

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.

Cash Flow

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


	Six Months Ended
	June 30,
	2016		2015
Net cash used in operating activities	$	(59,983)	$	(57,232)
Net cash used in investing activities	$	(27,164)	$	(593,669)
Net cash provided by financing activities	$	94,625	$	656,850

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 used in operating activities was $60.0 million and $57.2 million for the six months ended June 30, 2016 and 2015, respectively, for a period-over-period increase in cash used in operating activities of $2.8 million. The primary drivers of the change include the following (in thousands):


	Six Months Ended				Period over
	June 30,				Period
	2016		2015		Change
(Increase) decrease in accounts receivable	$	(46,838)	$	90,971	$	(137,809)
(Increase) in inventories	$	(55,042)	$	(72,788)	$	17,746
Decrease in accounts payable	$	(16,974)	$	(145,863)	$	128,889

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During the six months ended June 30, 2016, the increase in inventories and accounts receivable was 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. The increase in net cash used in operating activities also reflects the period-over-period decrease in net income of $54.4 million.

During the six months ended June 30, 2015, the decreases in accounts receivable and accounts payable were primarily due to the change in activity as we continued to exit the heating season. In addition, due to favorable market conditions, we elected to use our storage to carry increased levels of inventory.

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.

Net cash used in investing activities was $593.7 million for the six months ended June 30, 2015 and included $381.8 million, $156.3 million and $23.7 million in cash used to fund the acquisitions of Warren, Capitol and the Revere Terminal, respectively, $22.0 million in expansion capital expenditures and $11.2 million in maintenance capital expenditures, offset by $1.3 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, 2016 and 2015.

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 our sale leaseback transaction (see Note 6 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.

Net cash provided by financing activities was $656.8 million for the six months ended June 30, 2015 and included $295.1 million in proceeds from the issuance of our 7.00% senior notes, $168.2 million in net borrowings from our working capital revolving credit facility, $134.2 million in net borrowings from our revolving credit facility to fund the acquisitions of Warren, the Revere Terminal and Capitol, $109.3 million in net proceeds from our June 2015 issuance of common units and $1.9 million in capital contributions from our noncontrolling interest at Basin Transload. Net cash provided by financing activities was offset by $45.1 million in cash distributions to our common unitholders and our general partner, $3.6 million distributions to our noncontrolling interest at Basin Transload, $2.4 million in the repurchase of common units pursuant to our repurchase program for future satisfaction of our general partner’s obligations and $0.7 million in net payments on our line of credit related to Basin Transload.

Credit Agreement

Certain subsidiaries of ours, as borrowers, and we and certain of our subsidiaries, as guarantors, have a senior secured credit facility. On February 24, 2016, we entered into the fifth amendment to the credit agreement (the “Fifth Amendment”) which reflects, among other things, our voluntary election 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, for a total available commitment of $1.475 billion. We repay amounts outstanding and reborrow funds based on our working capital requirements and, therefore, classify as a current liability the portion of the working capital revolving credit facility we expect to pay down during the course of the year. The long-term portion of the working capital revolving credit facility is the amount we expect to be outstanding during the entire year. The credit agreement will mature on April 30, 2018.

As of June 30, 2016, the two facilities under the credit agreement included:

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

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a $575.0 million revolving credit facility to be used for acquisitions, joint ventures, capital expenditures, letters of credit and general corporate purposes.

In addition, the credit agreement has an accordion feature whereby we may request on the same terms and conditions of our then-existing credit agreement, provided no Event of Default (as defined in the credit agreement) then exists, an increase to the working capital revolving credit facility, the revolving credit facility, or both, by up to another $300.0 million, in the aggregate, for a total credit facility of up to $1.775 billion. 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 $1.475 billion.

In addition, the credit agreement includes a swing line pursuant to which Bank of America, N.A., as the swing line lender, may make swing line loans in U.S. Dollars in an aggregate amount equal to the lesser of (a) $50.0 million and (b) the Aggregate WC Commitments (as defined in the credit agreement). Swing line loans will bear interest at the Base Rate (as defined in the credit agreement). The swing line is a sub-portion of the working capital revolving credit facility and is not an addition to the total available commitments of $1.475 billion.

Availability under the working capital revolving credit facility is subject to a borrowing base which is redetermined from time to time 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). Pursuant to the Fifth Amendment, borrowings under the revolving credit facility bear interest at (1) the Eurocurrency rate plus 2.25% to 3.50%, (2) the cost of funds rate plus 2.25% to 3.50%, or (3) the base rate plus 1.25% to 2.50%, each depending on the Combined Total Leverage Ratio (as defined in the credit agreement).

The average interest rates for the credit agreement were 3.5% and 3.4% for the three months ended June 30, 2016 and 2015, respectively, and 3.7% and 3.4% for the six months ended June 30, 2016 and 2015, respectively.

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

As of June 30, 2016, we had total borrowings outstanding under the credit agreement of $582.2 million, including $213.4 million outstanding on the revolving credit facility. In addition, we had outstanding letters of credit of $66.9 million. Subject to borrowing base limitations, the total remaining availability for borrowings and letters of credit was $825.9 million and $1.2 billion at June 30, 2016 and December 31, 2015, respectively.

Our obligations under the credit agreement are secured by substantially all of our assets and the assets of our wholly-owned subsidiaries, and the credit agreement is guaranteed by us and our subsidiaries with the exception of Basin Transload.

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. The Fifth Amendment amended the definition of “Total Combined Leverage Ratio” to permit for an increased maximum ratio of 5.50:1.00 through the first quarter of 2017 and 5.00:1.00 thereafter. We were in compliance with the foregoing covenants at June 30, 2016. The credit agreement also contains a representation whereby there can be

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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).

6.25% Senior Notes

On June 19, 2014, we and GLP Finance Corp. (collectively, the “Issuers”) entered into a Purchase Agreement (the “Purchase Agreement”) with the Initial Purchasers (as defined therein) (the “Initial Purchasers”) pursuant to which the Issuers agreed to sell $375.0 million aggregate principal amount of the Issuers’ 6.25% senior notes due 2022 (the “6.25% Notes”) to the Initial Purchasers in a private placement exempt from the registration requirements under the Securities Act of 1933, as amended (the “Securities Act”). The 6.25% Notes were resold by the Initial Purchasers to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to persons outside the United States pursuant to Regulation S under the Securities Act.

Indenture

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

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

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

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Registration Rights Agreement

7.00% Senior Notes

Indenture

The 7.00% Notes will mature on June 15, 2023 with interest accruing at a rate of 7.00% per annum and payable semi-annually in arrears on June 15 and December 15 of each year, commencing December 15, 2015. The 7.00% Notes are guaranteed on a joint and several senior unsecured basis by each of the Issuers and the subsidiary guarantors to the extent set forth in the 7.00% Notes Indenture. Upon a continuing event of default, the trustee or the holders of at least 25% in principal amount of the 7.00% Notes may declare the 7.00% Notes immediately due and payable, except that an event of default resulting from entry into a bankruptcy, insolvency or reorganization with respect to us, any restricted subsidiary of ours that is a significant subsidiary or any group of our restricted subsidiaries that, taken together, would constitute a significant subsidiary of ours, will automatically cause the 7.00% Notes to become due and payable.

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certain asset sales or a Change of Control (as defined in the 7.00% Notes Indenture) at the prices and on the terms specified in the 7.00% Notes Indenture.

The 7.00% Notes Indenture contains covenants that will limit our ability to, among other things, incur additional indebtedness and issue preferred securities, make certain dividends and distributions, make certain investments and other restricted payments, restrict distributions by our subsidiaries, create liens, enter into sale-leaseback transactions, sell assets or merge with other entities. Events of default under the 7.00% Notes Indenture include (i) a default in payment of principal of, or interest or premium, if any, on, the 7.00% Notes, (ii) breach of our covenants under the 7.00% Notes Indenture, (iii) certain events of bankruptcy and insolvency, (iv) any payment default or acceleration of indebtedness of ours or certain subsidiaries if the total amount of such indebtedness unpaid or accelerated exceeds $50.0 million and (v) failure to pay within 60 days uninsured final judgments exceeding $50.0 million.

Registration Rights Agreement

Financing Obligations

Capitol Acquisition

In connection with the Capitol acquisition on June 1, 2015, 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 term 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 $2.4 million and $0.8 million was recorded for the three months ended June 30, 2016 and 2015, respectively, and $4.8 million and $0.8 million was recorded for the six months ended June 30, 2016 and 2015, respectively, and is included in interest expense in the accompanying statements of operations. The financing obligation will amortize through expiration of the lease based upon the lease rental payments which were $2.4 million and $0.8 million for the three months ended June 30, 2016 and 2015, respectively, and $4.7 million and $0.8 million for the six months ended June 30, 2016 and 2015, respectively. The financing obligation balance outstanding at June 30, 2016 was $89.9 million associated with the Capitol.

Sale Leaseback Transaction

On June 29, 2016, we, through our wholly owned subsidiaries, Global Companies, GMG and Alliance, and Alliance’s wholly owned subsidiary, Bursaw, 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.

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The sale did not meet the criteria for sale accounting as of June 30, 2016 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, 2016, respectively.

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 will continue 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 will incur interest expense associated with the financing obligation. Lease rental payments will be recognized as both interest expense and a reduction of the principal balance associated with the financing obligation. 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, 2016 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. We capitalized additional financing fees of $1.0 million for each of the three and six months ended June 30, 2016, including recording, deed transfer, survey and legal fees associated with the financing obligation recognized as part of the Sale Leaseback Transaction. We had unamortized deferred financing fees of $17.2 million and $19.0 million at June 30, 2016 and December 31, 2015, respectively.

Unamortized fees related to the credit agreement are included in other current assets and other long-term assets and amounted to $9.0 million and $11.2 million at June 30, 2016 and December 31, 2015, 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 $7.2 million and $7.8 million at June 30, 2016 and December 31, 2015, 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 $1.0 million at June 30, 2016.

On February 24, 2016, 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 its deferred financing fees. These expenses are included in interest expense in the accompanying statement of operations for the six months ended June 30, 2016.

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

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financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results may differ from these estimates under different assumptions or conditions.

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

Goodwill

Goodwill represents the future economic benefits arising from assets acquired in a business combination that are not individually identified and separately recognized. We concluded that our operating segments are also our reporting units. At June 30, 2016 and December 31, 2015, goodwill recorded in the accompanying consolidated balance sheets aggregated $435.4 million, of which $121.7 million relates to the Wholesale reporting unit and $313.7 million relates to the GDSO reporting unit. Goodwill associated with our disposition activities of GDSO sites will be included in the carrying value of assets sold in determining the gain or loss on disposal. No goodwill has been derecognized as of June 30, 2016.

Goodwill is tested for impairment annually as of October 1 or when events or changes in circumstances indicate that the carrying amount of goodwill may not be recoverable. The process of testing goodwill for impairment involves numerous judgments, assumptions and estimates made by management which inherently reflect a high degree of uncertainty. The impairment test first includes a qualitative assessment in order to conclude if it is more likely than not that the reporting unit’s fair value exceeds its carrying value. Factors considered in the qualitative analysis include changes in the business and industry, as well as macro-economic conditions, that would influence the fair value of the reporting unit as well as changes in the carrying values of the reporting unit. If necessary, we will then complete a two-step quantitative assessment. In the quantitative assessment, the fair value of each reporting unit is determined and compared to the book value of the reporting unit. If the fair value of the reporting unit is less than the book value, including goodwill, then the recorded goodwill is impaired to its implied fair value with a charge to operations. We calculate the fair value of each reporting unit using a combination of discounted cash flows and market comparables.

Key assumptions included in the development of the discounted cash flow value for each reporting unit include:

Future commodity volumes and margins. The discounted cash flows are based on a five-year forecast with an estimate of terminal values. In general, our reporting units’ fair values are most sensitive to volume and gross margin assumptions. In particular, our Wholesale segment’s cash flows are impacted by the crude oil market, given our 2013 investment in transloading terminals in North Dakota and Oregon. The significant decline in the price of crude oil and tight crude oil differentials negatively impacted our fiscal 2015 results. We expect low crude oil prices and tight differentials to continue for a period of time, which has negatively impacted and will continue to negatively impact our 2016 performance, with forecasted recovery expected sometime in 2017. However, with the continuation of low crude oil prices and tight differentials, our assumptions as to the timing of a market recovery, particularly in crude oil, might be more extended than currently estimated within our five-year forecast and estimate of terminal values. If market conditions do not improve or timing of recovery is extended and does not become more certain, we may change such assumptions in future periods. As a result of these market conditions, there is increased uncertainty and sensitivity relating to our future cash flow projections within our crude oil business on which the Wholesale reporting unit’s goodwill impairment analysis relies. If market conditions, and therefore our performance, are worse than our projections, we may record impairment charges in the future. Actual results may not be consistent with these judgments, assumptions and estimates, and goodwill impairment charges may be required in future periods. This could have an adverse impact on our financial position and results of operations.

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Discount rate commensurate with the risks involved. We apply a discount rate to our expected cash flows based on a variety of factors, including market and economic conditions, operational risk, regulatory risk and political risk. A higher discount rate decreases the net present value of cash flows.

Future capital requirements. Our estimates of future capital requirements are based upon a combination of authorized spending and internal forecasts.

On October 1, 2015, we completed our quantitative assessments for both the Wholesale and GDSO reporting units, and no impairment indicator was identified for either reporting unit. The declining crude oil prices, changes in certain market conditions and decline in our common unit price, collectively caused us to reassess our goodwill for impairment as of December 31, 2015 for the Wholesale reporting unit. Based on the results of this assessment, we concluded that step two of the quantitative assessment was not necessary and no impairment was required.

As of June 30, 2016, we considered whether there was any change of circumstances or events during the second quarter which would more likely than not reduce the fair value of the Wholesale segment’s reporting unit below its carrying amount. We concluded that such events and circumstances have not occurred. However, with the continuation of low crude oil prices and tight differentials, our assumptions as to the timing of a market recovery, particularly in crude oil, might be more extended than currently estimated within our five-year forecast and estimate of terminal values. If market conditions do not improve or timing of recovery is extended and does not become more certain, we may change such assumptions in future periods, which could result in a different conclusion. We continue to monitor the extent and timing of future demand, which may impact the timing of forecasted recovery.

The fair values of our reporting units are based on underlying assumptions that represent our best estimates. Many of the factors used in assessing fair value are outside of the control of management. A further sustained decline in commodity prices may cause us to reassess our long-lived assets and goodwill for impairment and could result in future non-cash impairment charges as a result of such impairment assessments. If we are required to perform step two in the future for the Wholesale reporting unit, up to $121.7 million of goodwill assigned to this reporting unit could be written off in the period of such impairment assessment.

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, 2015. Except as discussed below, 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 19 of Notes to Consolidated Financial Statements included elsewhere in this report.

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, 2016, we had total borrowings outstanding under our credit agreement of $582.2 million. Please read Item 2, “Management’s Discussion and Analysis—Liquidity and Capital Resources——Credit Agreement,” for

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information on interest rates related to our borrowings. The impact of a 1% increase in the interest rate on this amount of debt would have resulted in an increase in interest expense, and a corresponding decrease in our results of operations, of approximately $5.8 million annually, assuming, however, that our indebtedness remained constant throughout the year.

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

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

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

In the aggregate, these hedging instruments historically have been effective in hedging the variability in interest payments due to changes in the one-month LIBOR swap curve or rate with respect to $300.0 million of one-month LIBOR-based borrowings on the credit facility. In June 2014 and as a result of the issuance of our $375.0 million aggregate principal amount of the 6.25% senior notes due 2022s (see Note 6 of Notes to Consolidated Financial Statements), we determined that maintaining an excess of $300.0 million in principal of outstanding floating-rate debt was no longer probable. Therefore, we elected to de-designate our interest rate cap and discontinued the related hedge accounting for this instrument. The interest rate cap, which expired on April 13, 2016, was not in a hedging relationship for the three and months ended June 30, 2016 and 2015. Accordingly, all changes in fair value of this instrument were recorded in the consolidated statements of operations through interest expense.

At June 30, 2016, 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 5 of Notes to Consolidated Financial Statements for additional information on our derivative instruments.

Commodity Risk

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

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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 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, 2016, 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):


			Gain (Loss)
	Fair Value at
	June 30,		Effect of 10%		Effect of 10%
	2016		Price Increase		Price Decrease
Exchange traded derivative contracts	$	(48,226)	$	(38,569)	$	38,569
Forward derivative contracts		5,502		(8,527)		8,527
	$	(42,724)	$	(47,096)	$	47,096

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, 2016. 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 $39.4 million at June 30, 2016.

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.

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Item 4.Controls and Procedures.

Disclosure Controls and Procedures

We maintain disclosure controls and procedures that are designed to ensure that the information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act of 1934 (the “Exchange Act”) is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms and that information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure. Under the supervision and with the participation of our principal executive officer and principal financial officer, management evaluated the effectiveness of our disclosure controls and procedures (as defined in 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 effective at the reasonable assurance level as of June 30, 2016.

Internal Control Over Financial Reporting

There has not been any change in our internal control over financial reporting that occurred during the quarter ended June 30, 2016 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 12 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 recently 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 was impacted. We have notified the EPA. 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 Clean Air Act (the “CAA”). The information requested generally relates 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 (“DEC”) 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 New York State Department of Environmental Conservation (“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 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 DEC comply with the CAA and applicable State air permitting requirements and that no material violation of law has occurred. We will contest the claims alleged in 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, 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 at our Albany Terminal, particularly with respect to crude oil operations at the Albany Terminal. The October NOI revises the superseded and replaced 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, 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 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 they 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 and a decision from the Court is expected during the third quarter of 2016. At this time, all discovery and other litigation activity is stayed pending a decision by the Court on the motion to dismiss.

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 requires us to submit a plan to remedy the reported violations of the NPDES Permit. We have responded to the NON with a plan and are implementing modifications to the storm water management system at the Revere Terminal. We have determined that compliance with the NON and implementation of the plan will have no material impact on our operations.

We had a dispute with Lansing Ethanol Services, LLC (“Lansing”) for damages in excess of $12.0 million. The dispute involved Lansing’s failure to transfer Renewable Fuel Identification Numbers to us in connection with certain agreements for the purchase and sale of ethanol. The parties had agreed to arbitrate under the rules of the American Arbitration Association. We filed for arbitration on March 24, 2015 and the hearing was conducted in March 2016. A decision was rendered on June 10, 2016, which netted us approximately $1.5 million. Neither party appealed the decision and the appeal period expired on July 14, 2016. The parties executed a Settlement Agreement and Mutual Release on August 2, 2016, and payment was made by Lansing and received by us on that date.

On May 16, 2014, we received a subpoena from the SEC requesting information for relevant time periods primarily relating to our accounting for RINs and the restatement of our consolidated financial statements as of and for the quarters ended March 31, 2013, June 30, 2013 and September 30, 2013. We have cooperated fully with the SEC and believe we have provided the SEC with all requested materials.

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 was extended on May 17, 2016 and further extended on August 2, 2016. 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, 2015, 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 8, 2016		By:	/s/ Eric Slifka
			Eric Slifka
			President and Chief Executive Officer
			(Principal Executive Officer)


Dated: August 8, 2016		By:	/s/ Daphne H. Foster
			Daphne H. Foster
			Chief Financial Officer
			(Principal Financial Officer)

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INDEX TO EXHIBITS SEE OTHER LIST


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

4.3	—	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).

4.4	—	Registration Rights Agreement, dated June 4, 2015, among the Issuers, the Guarantors and the Initial Purchasers (incorporated herein by reference to Exhibit 4.2 to the Current Report on Form 8-K filed on June 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.