Sprague Resources LP - Quarter Report: 2021 June (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q


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

For the quarterly period ended June 30, 2021


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

For the transition period from to

Commission file number: 001-36137

Sprague Resources LP

(Exact name of registrant as specified in its charter)


Delaware						45-2637964
(State of incorporation)						(I.R.S. Employer Identification No.)

185 International Drive

Portsmouth, New Hampshire 03801

(Address of principal executive offices)

Registrant’s telephone number, including area code: (800) 225-1560

Securities registered pursuant to Section 12(b) of the Act:


Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common Units Representing Limited Partner Interests	SRLP	New York Stock Exchange

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 every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐

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


Large accelerated filer	☐	Accelerated filer	☒
Non-accelerated filer	☐	Smaller reporting company	☐
Emerging growth company	☐

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

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

The registrant had 26,226,255 common units outstanding as of August 5, 2021.

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		Page
PART I—FINANCIAL INFORMATION

Item 1.	Financial Statements:
	Condensed Consolidated Balance Sheets as of June 30, 2021 (unaudited) and December 31, 2020	1
	Unaudited Condensed Consolidated Income Statements for the three and six months ended June 30, 2021 and June 30, 2020	2
	Unaudited Condensed Consolidated Statements of Comprehensive (Loss) Income for the three and six months ended June 30, 2021 and June 30, 2020	3
	Unaudited Condensed Consolidated Statements of Unitholders’ Equity for the three and six months ended June 30, 2021 and June 30, 2020	4
	Unaudited Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2021 and June 30, 2020	5
	Notes to Unaudited Condensed Consolidated Financial Statements	6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	21
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	39
Item 4.	Controls and Procedures	42

PART II—OTHER INFORMATION

Item 1.	Legal Proceedings	43
Item 1A.	Risk Factors	43
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	43
Item 3.	Defaults Upon Senior Securities	43
Item 4.	Mine Safety Disclosures	43
Item 5.	Other Information	43
Item 6.	Exhibits	44
Signatures		46

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Part I – FINANCIAL INFORMATION


Item 1 — Condensed Consolidated Financial Statements

Sprague Resources LP

Condensed Consolidated Balance Sheets

(in thousands except unit amounts)


	June 30, 2021		December 31, 2020
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	6,750	$	3,771
Accounts receivable, net	158,200		193,015
Inventories	202,646		255,533
Fair value of derivative assets	115,329		145,957
Other current assets	17,022		67,406
Total current assets	499,947		665,682
Fair value of derivative assets, long-term	21,870		20,021
Property, plant and equipment, net	328,572		335,296
Intangibles, net	37,434		41,142
Other assets, net	20,362		22,252
Goodwill	115,037		115,037
Total assets	$	1,023,222	$	1,199,430
Liabilities and unitholders’ equity
Current liabilities:
Accounts payable	$	50,969	$	97,280
Accrued liabilities	76,575		46,645
Fair value of derivative liabilities	144,118		154,105
Due to General Partner	4,945		10,915
Current portion of working capital facilities	246,598		358,685
Current portion of other obligations	7,281		6,968
Total current liabilities	530,486		674,598
Commitments and contingencies

Acquisition facility	377,400		382,400
Fair value of derivative liabilities, long-term	26,968		20,240
Other obligations, less current portion	37,335		39,309
Operating lease liabilities, less current portion	2,371		5,653
Due to General Partner	2,899		2,751
Deferred income taxes	15,572		15,784
Total liabilities	993,031		1,140,735
Unitholders’ equity:
Common unitholders - public (8,052,406 and 9,995,069 units issued and outstanding as of June 30, 2021 and December 31, 2020, respectively)	112,626		154,238
Common unitholders - affiliated (18,173,849 and 12,951,236 units issued and outstanding as of June 30, 2021 and December 31, 2020, respectively)	(60,910)		(69,561)
Accumulated other comprehensive loss, net of tax	(21,525)		(25,982)
Total unitholders’ equity	30,191		58,695
Total liabilities and unitholders’ equity	$	1,023,222	$	1,199,430

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

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Sprague Resources LP

Unaudited Condensed Consolidated Income Statements

(in thousands except unit and per unit amounts)


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Net sales	$	657,672	$	358,214	$	1,693,805	$	1,318,093
Cost of products sold (exclusive of depreciation and amortization)	659,803		325,233		1,584,585		1,175,252
Operating expenses	19,148		18,471		38,379		39,283
Selling, general and administrative	16,719		18,923		41,958		38,956
Depreciation and amortization	8,258		8,518		16,741		17,115
Total operating costs and expenses	703,928		371,145		1,681,663		1,270,606
Other operating income	9,725		—		9,725		—
Operating (loss) income	(36,531)		(12,931)		21,867		47,487
Other income	—		64		2		64
Interest income	77		72		143		248
Interest expense	(8,587)		(10,788)		(17,402)		(22,074)
(Loss) income before income taxes	(45,041)		(23,583)		4,610		25,725
Income tax provision	(562)		(1,542)		(1,433)		(4,113)
Net (loss) income	(45,603)		(25,125)		3,177		21,612
Incentive distributions declared	—		(2,072)		—		(4,144)
Limited partners' interest in net (loss) income	$	(45,603)	$	(27,197)	$	3,177	$	17,468

Net (loss) income per limited partner unit:
Common - basic	$	(1.74)	$	(1.19)	$	0.13	$	0.76
Common - diluted	$	(1.74)	$	(1.19)	$	0.13	$	0.76
Units used to compute net income per limited partner unit:
Common - basic	26,226,255		22,922,902		25,066,494		22,871,943
Common - diluted	26,226,255		22,922,902		25,066,494		22,937,273
Distribution declared per unit	$	0.6675	$	0.6675	$	1.3350	$	1.3350

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

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Sprague Resources LP

Unaudited Condensed Consolidated Statements of Comprehensive (Loss) Income

(in thousands)


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Net (loss) income	$	(45,603)	$	(25,125)	$	3,177	$	21,612
Other comprehensive income (loss), net of tax:
Unrealized gain (loss) on interest rate swaps
Net (loss) gain arising in the period	(208)		(1,257)		1,598		(9,785)
Reclassification adjustment related to loss (gain) realized in income	1,459		1,441		2,815		2,056
Net change in unrealized gain (loss) on interest rate swaps	1,251		184		4,413		(7,729)
Tax effect	(10)		(1)		(34)		60
	1,241		183		4,379		(7,669)
Foreign currency translation adjustment	42		123		78		(191)
Other comprehensive income (loss)	1,283		306		4,457		(7,860)
Comprehensive (loss) income	$	(44,320)	$	(24,819)	$	7,634	$	13,752

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

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Sprague Resources LP

Unaudited Condensed Consolidated Statements of Unitholders’ Equity

(in thousands)


	Common- Public		Common- Affiliated		Incentive Distribution Rights		Accumulated Other Comprehensive Loss		Total

Three Months Ended June 31, 2020 and 2021
Balance at March 31, 2020	$	194,513	$	(48,474)	$	—	$	(27,854)	$	118,185
Net loss	(12,610)		(14,568)		2,053		—		(25,125)
Other comprehensive income	—		—		—		306		306
Unit-based compensation	397		458		—		—		855
Distributions paid in cash	(7,139)		(8,162)		(2,072)		—		(17,373)
Distributions paid in units	—		(19)		19		—		—
Units purchased by Sprague Holdings in Private Transaction	(12,086)		12,086		—		—		—

Balance at June 30, 2020	$	163,075	$	(58,679)	$	—	$	(27,548)	$	76,848

Balance at March 31, 2021	$	166,680	$	(51,855)	$	—	$	(22,808)	$	92,017
Net loss	(16,346)		(29,257)		—		—		(45,603)
Other comprehensive income	—		—		—		1,283		1,283

Distributions paid in cash	(6,787)		(10,719)		—		—		(17,506)


Increase in affiliated units as a result of acquisition by Hartree Partners, LP	(30,921)		30,921		—		—		—


Balance at June 30, 2021	$	112,626	$	(60,910)	$	—	$	(21,525)	$	30,191

Six Months Ended June 30, 2020 and 2021
Balance at December 31, 2019	$	180,302	$	(66,832)	$	—	$	(19,688)	$	93,782
Net income	8,229		9,258		4,125		—		21,612
Other comprehensive loss	—		—		—		(7,860)		(7,860)
Unit-based compensation	588		673		—		—		1,261
Distributions paid in cash	(14,242)		(16,243)		(2,072)		—		(32,557)
Distributions paid in units	—		2,053		(2,053)		—		—
Units purchased by Sprague Holdings in Private Transaction	(12,086)		12,086		—		—		—
Common units issued in connection with annual bonus	423		484		—		—		907
Units withheld for employee tax obligations	(139)		(158)		—		—		(297)
Balance at June 30, 2020	$	163,075	$	(58,679)	$	—	$	(27,548)	$	76,848

Balance at December 31, 2020	$	154,238	$	(69,561)	$	—	$	(25,982)	$	58,695
Net income	3,289		(2,186)		2,074		—		3,177
Other comprehensive income	—		—		—		4,457		4,457
Unit-based compensation	(1,373)		(1,894)		—		—		(3,267)
Distributions paid in cash	(13,459)		(19,364)		(2,074)		—		(34,897)

Increase in affiliated units as a result of acquisition by Hartree Partners, LP	(30,921)		30,921		—		—		—
Common units issued in connection with annual bonus	1,461		2,014		—		—		3,475
Units withheld for employee tax obligations	(609)		(840)		—		—		(1,449)
Balance at June 30, 2021	$	112,626	$	(60,910)	$	—	$	(21,525)	$	30,191

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

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Sprague Resources LP

Unaudited Condensed Consolidated Statements of Cash Flows

(in thousands)


	Six Months Ended June 30,
	2021		2020
Cash flows from operating activities
Net income	$	3,177	$	21,612
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization (includes amortization of deferred debt issuance costs)	19,297		20,040
(Gain) loss on sale of assets	(9,840)		27
Changes in fair value of contingent consideration	—		244
Provision for doubtful accounts	98		539
Non-cash unit-based compensation	208		1,261

Deferred income taxes	(246)		(603)
Changes in assets and liabilities:
Accounts receivable	34,716		173,829
Inventories	52,888		96,785
Other assets	54,266		7,576
Fair value of commodity derivative instruments	29,933		(29,654)
Due to General Partner and affiliates	(6,295)		(1,125)
Accounts payable, accrued liabilities and other	(19,050)		(113,250)
Net cash provided by operating activities	159,152		177,281
Cash flows from investing activities
Purchases of property, plant and equipment	(5,799)		(5,386)
Proceeds from sale of assets	11,125		241
Net cash provided by (used in) investing activities	5,326		(5,145)
Cash flows from financing activities
Net payments under credit agreements	(117,383)		(131,618)
Payments on finance leases, term debt, and other obligations	(3,335)		(2,804)
Debt issue costs	(4,430)		(5,669)
Distributions to unitholders	(34,897)		(32,557)
Units withheld for employee tax obligations	(1,450)		(297)
Net cash used in financing activities	(161,495)		(172,945)
Effect of exchange rate changes on cash balances held in foreign currencies	(4)		(829)
Net change in cash and cash equivalents	2,979		(1,638)
Cash and cash equivalents, beginning of period	3,771		5,386
Cash and cash equivalents, end of period	$	6,750	$	3,748
Supplemental disclosure of cash flow information
Cash paid for interest	$	14,476	$	20,424
Cash paid for taxes	$	6,165	$	1,434
Assets acquired under finance lease obligations	$	1,580	$	609
Cash paid for operating leases	$	3,068	$	3,085
Distribution paid in units	$	—	$	2,053

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

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Sprague Resources LP

Notes to Unaudited Condensed Consolidated Financial Statements

(in thousands unless otherwise stated)

1. Description of Business and Summary of Significant Accounting Policies

Partnership Businesses

Sprague Resources LP (the “Partnership”) is a Delaware limited partnership formed on June 23, 2011 by Sprague Holdings and its General Partner and engages in the purchase, storage, distribution and sale of refined products and natural gas, and provides storage and handling services for a broad range of materials.

On April 20, 2021, the Partnership and Hartree Partners, LP ("Hartree") announced that Sprague Holdings entered into an agreement to sell to Sprague HP Holdings, LLC (a wholly-owned subsidiary of Hartree) the interest of Sprague Holdings in the General Partner, the incentive distribution rights and all of the common units representing limited partner interests that Sprague Holdings owned in the Partnership (the “Transaction”). The Transaction was completed and effective on May 28, 2021.

Unless the context otherwise requires, prior to May 28, 2021, references referring to “Sprague Resources,” and the “Partnership,” refer to Sprague Resources LP and its subsidiaries; references to the "General Partner" refer to Sprague Resources GP LLC; references to “Axel Johnson” or the "Sponsor" refer to Axel Johnson Inc. and its controlled affiliates, collectively, other than Sprague Resources, its subsidiaries and its General Partner; references to “Sprague Holdings” refer to Sprague Resources Holdings LLC, a wholly owned subsidiary of Axel Johnson and the owner of the General Partner.

Unless the context otherwise requires, effective May 28, 2021, references referring to Sprague Resources, and the Partnership, refer to Sprague Resources LP and its subsidiaries; references to the General Partner refer to Sprague Resources GP LLC; references to “Hartree” or the Sponsor refer to Hartree Partners, LP, other than Sprague Resources, its subsidiaries and its General Partner; references to “Sprague Holdings” refer to Sprague HP Holdings LLC, a wholly owned subsidiary of Hartree and the owner of the General Partner.

The Partnership owns, operates and/or controls a network of refined products and materials handling terminals located in the Northeast United States and in Quebec, Canada. The Partnership also utilizes third-party terminals in the Northeast United States through which it sells or distributes refined products pursuant to rack, exchange and throughput agreements. The Partnership has four reportable segments: refined products, natural gas, materials handling and other operations.

•The refined products segment purchases a variety of refined products, such as heating oil, diesel fuel, residual fuel oil, kerosene, jet fuel and gasoline - primarily from refining companies, trading organizations and producers - and sells them to wholesale and commercial customers.

•The natural gas segment purchases natural gas from natural gas producers and trading companies and sells and distributes natural gas to commercial and industrial customers.

•The materials handling segment offloads, stores and prepares for delivery a variety of customer-owned products, including asphalt, clay slurry, salt, gypsum, crude oil, residual fuel oil, coal, petroleum coke, caustic soda, tallow, pulp, and heavy equipment.

•The other operations segment primarily includes the marketing and distribution of coal and certain commercial trucking activities.

See Note 2 - Revenue for a description of the Partnership's revenue activities within these business segments.

As of June 30, 2021, the Sponsor, through its ownership of Sprague Holdings, owned 18,173,849 common units (consisting of the 16,058,484 common units purchased as part of the Transaction and 2,115,365 common units beneficially owned by Hartree prior to the consummation of the Transaction) representing 69.3% of the limited partner interest in the Partnership. As of June 30, 2021, Hartree Bulk Storage, LLC and HP Bulk Storage Manager, LLC, (uncontrolled affiliates of Hartree Partners LP) beneficially own an additional 1,375,000 common units which are included in the public units outstanding. Sprague Holdings also owns the General Partner, which in turn owns a non-economic interest in the Partnership. Sprague Holdings currently holds incentive distribution rights (“IDRs”) that entitle it to receive increasing percentages, up to a maximum of 50.0%, of the cash the Partnership distributes from distributable cash flow in excess of $0.7676 per unit per quarter ($0.4744 prior to the consummation of the IDR Reset Election, as described below). The maximum distribution of 50% does not include any distributions that Sprague Holdings may receive on any limited partner units that it owns. See Note 12 - Earnings Per Unit and Note 13 - Partnership Distributions.

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On February 11, 2021, Sprague Holdings provided notice to the Partnership that Sprague Holdings had made an IDR Reset Election (the “IDR Reset Election”), as defined in the First Amended and Restated Agreement of Limited Partnership of the Partnership (as amended, the “Partnership Agreement”). Pursuant to the IDR Reset Election, Sprague Holdings relinquished the right to receive incentive distribution payments based on the minimum quarterly and target cash distribution levels set at the time of the Partnership’s initial public offering and the Partnership issued 3,107,248 common units to Sprague Holdings. Pursuant to the IDR Reset Election, the minimum quarterly distribution amount increased from $0.4125 per common unit per quarter to $0.6675 per common unit per quarter and the levels at which the incentive distribution rights participate in distributions were reset at higher amounts based on then-current common unit distribution rates and a formula in the Partnership Agreement. The IDR Reset Election was effective on March 5, 2021.

On April 29, 2021, the Partnership sold the Oswego terminal to an unaffiliated buyer. In connection with the sale, we recorded a net gain on the sale of $9.0 million for the quarter ended June 30, 2021, which is included within other operating income in the consolidated statements of income. The remaining $0.7 million of other operating income relates to a gain associated with a parcel of land sold at the Bronx terminal.

Basis of Presentation

The Condensed Consolidated Financial Statements include the accounts of the Partnership and its wholly-owned subsidiaries. Intercompany transactions between the Partnership and its subsidiaries have been eliminated. The accompanying unaudited Condensed Consolidated Financial Statements were prepared in accordance with the requirements of the Securities and Exchange Commission (“SEC”) for interim financial information. As permitted under those rules, certain notes or other financial information that are normally required by U.S. generally accepted accounting principles (“GAAP”) to be included in annual financial statements have been condensed or omitted from these interim financial statements. These interim financial statements should be read in conjunction with the consolidated financial statements and related notes of the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2020 as filed with the SEC on March 5, 2021 (the “2020 Annual Report”).

The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities in the balance sheet and the reported net sales and expenses in the income statement. Actual results could differ from those estimates. Among the estimates made by management are the fair value of derivative assets and liabilities, valuation of contingent consideration, valuation of reporting units within the goodwill impairment assessment, and if necessary long-lived asset impairments and environmental and legal obligations.

The Condensed Consolidated Financial Statements included herein reflect all normal and recurring adjustments which, in the opinion of management, are necessary for a fair presentation of the Partnership’s consolidated financial position at June 30, 2021 and December 31, 2020, the consolidated results of operations for the three and six months ended June 30, 2021 and 2020, consolidated statement of changes in unitholders' equity for the three and six months ended June 30, 2021 and 2020, and the consolidated cash flows for the six months ended June 30, 2021 and 2020. The unaudited results of operations for the interim periods reported are not necessarily indicative of results to be expected for the full year. Demand for some of the Partnership’s refined petroleum products, specifically heating oil and residual oil for space heating purposes, and to a lesser extent natural gas, are generally higher during the first and fourth quarters of the calendar year which may result in significant fluctuations in the Partnership’s quarterly operating results.

COVID-19

The global outbreak of the novel coronavirus (COVID-19) was declared a pandemic by the World Health Organization and a national emergency by the U.S. Government in March 2020 and has negatively affected the U.S. and global economy, disrupted global supply chains, resulted in significant travel and transport restrictions, including mandated closures and orders to “shelter-in-place,” and created significant disruption of the financial markets.

Beginning in the quarterly period ended March 31, 2020, a wide array of sectors including but not limited to the energy, transportation, manufacturing and commercial, along with global economic conditions generally, have been significantly disrupted by the pandemic. A growing number of the Partnership’s customers in these industries have experienced substantial reductions in their operations due to travel restrictions as well as the extended shutdown of various businesses in affected regions. Furthermore, government measures have also led to a precipitous decline in fuel prices in response to concerns about demand for fuel.

The pandemic and associated impacts on economic activity had an adverse effect on the Partnership’s operating results for the three and six months ended June 30, 2021, specifically, the Partnership has seen a decline in demand and related sales

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volume as large sectors of the global economy have been adversely impacted by the crisis. In response to these developments, the Partnership took swift action to ensure the safety of employees and other stakeholders, and initiated a number of initiatives relating to cost reduction, liquidity and operating efficiencies.

The Partnership makes estimates and assumptions that affect the reported amounts on these condensed consolidated financial statements and accompanying notes as of the date of the financial statements. The Partnership assessed accounting estimates that require consideration of forecasted financial information, including, but not limited to, the allowance for credit losses, the carrying value of goodwill, intangible assets, and other long-lived assets. This assessment was conducted in the context of information reasonably available to the Partnership, as well as consideration of the future potential impacts of COVID-19 on the Partnership’s business as of June 30, 2021. While market conditions for our products and services have improved when compared to a year ago, the pandemic remains fluid, indicating that the full impact may not have been realized across our business and operations. The economic and operational landscape has been altered, and it is difficult to determine whether such changes are temporary or permanent, with challenges related to staffing, supply chain, and transportation globally. The Partnership continues to monitor the evolving impacts of COVID-19 and variants closely and respond to changing conditions.

Significant Accounting Policies

The Partnership's significant accounting policies are described in Note 1 - Description of Business and Summary of Significant Accounting Policies in the Partnership’s audited consolidated financial statements included in the 2020 Annual Report and are the same as are used in preparing these unaudited interim Condensed Consolidated Financial Statements.

Recent Accounting Pronouncements

In March 2020, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2020-04, Reference Rate Reform (Topic 848) which provides optional expedients and exceptions for applying U.S. GAAP to contracts, hedging relationships and other transactions affected by reference rate reform, if certain criteria are met. The amendments apply only to contracts, hedging relationships, and other transactions that reference LIBOR or another reference rate expected to be discontinued because of reference rate reform. These amendments are effective immediately and may be applied prospectively to contract modifications made and hedging relationships entered into or evaluated on or before December 31, 2022. The Partnership has not currently adopted the optional expedients and exceptions provided in this guidance but continues to monitor and evaluate the impact of reference rate reform on relevant transactions.

2. Revenue

Disaggregated Revenue

In general, the Partnership's business segmentation is aligned according to the nature and economic characteristics of its products and customer relationships which provides meaningful disaggregation of each business segment's results of operations. The Partnership operates its businesses in the Northeast and Mid-Atlantic United States and Eastern Canada.

The refined products segment purchases a variety of refined products, such as heating oil, diesel fuel, residual fuel oil, kerosene, jet fuel and gasoline (primarily from refining companies, trading organizations and producers), and sells them to wholesale and commercial customers. Refined products revenue-producing activities are direct sales to customers, including throughput transactions. Revenue is recognized when the product is delivered. Revenue is not recognized on exchange agreements, which are entered into primarily to acquire refined products by taking delivery of products closer to the Partnership’s end markets. Rather, net differentials or fees for exchange agreements are recorded within cost of products sold (exclusive of depreciation and amortization).

The natural gas segment purchases natural gas from natural gas producers and trading companies and sells and distributes natural gas to commercial and industrial customers. Natural gas revenue-producing activities are sales to customers at various points on natural gas pipelines or at local distribution companies (i.e., utilities). Natural gas sales not billed by month-end are accrued based upon gas volumes delivered.

The materials handling segment offloads, stores and prepares for delivery a variety of customer-owned products. A majority of the materials handling segment revenue is generated under leasing arrangements with revenue recorded over the lease term generally on a straight-line basis. Contingent rentals are recorded as revenue only when billable under the arrangement. For materials handling contracts that are not leases, the Partnership recognizes revenue either at a point in time

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after services are performed or over a period of time if the services are performed in a continuous fashion over the period of the contract as these methods represent a faithful depiction of the transfer of goods and services.

The other operations segment primarily includes the marketing and distribution of coal and certain commercial trucking activities. Revenue from other operations is recognized when the product is delivered or the services are rendered.

Further disaggregation of net sales by business segment and geographic destination is as follows:


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Net sales:
Refined products
Distillates	$	410,551	$	219,599	$	1,163,478	$	915,427
Gasoline	124,550		43,688		219,596		119,965
Heavy fuel oil and asphalt	54,041		29,602		122,268		99,439
Total refined products	$	589,142	$	292,889	$	1,505,342	$	1,134,831
Natural gas	51,360		47,988		153,935		143,766
Materials handling	12,725		12,974		24,771		28,531
Other operations	4,445		4,363		9,757		10,965
Net sales	$	657,672	$	358,214	$	1,693,805	$	1,318,093

Net sales by country:
United States	$	584,726	$	324,058	$	1,554,617	$	1,230,867
Canada	72,946		34,156		139,188		87,226
Net sales	$	657,672	$	358,214	$	1,693,805	$	1,318,093

Contract Balances

Contract liabilities primarily relate to advances or deposits received from the Partnership's customers before revenue is recognized. These amounts are included in accrued liabilities and amounted to $7.1 million and $9.4 million as of June 30, 2021 and December 31, 2020, respectively. A substantial portion of the contract liabilities as of December 31, 2020 remains outstanding as of June 30, 2021 as they are primarily deposits. The Partnership does not have any material contract assets as of June 30, 2021 or December 31, 2020.

3. Leases

From a lessor perspective, the Partnership has entered into various throughput and materials handling arrangements with customers. These arrangements are accounted for as operating leases as determined by the use terms and rights outlined in the underlying agreements. The throughput contracts are agreements with refined products wholesalers that use the Partnership’s terminal facilities for a fee. The materials handling contracts are arrangements involving rentals of dedicated tanks, pads, land and small office locations for the purposes of storage, parking and other related uses. Income related to the operating leases with the Partnership as the lessor, as described above, totaled $9.8 million and $10.8 million for the three months ended June 30, 2021 and 2020, respectively, and $20.3 million and $20.3 million for the six months ended June 30, 2021 and 2020, respectively.

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4. Accumulated Other Comprehensive Loss, Net of Tax

Amounts included in accumulated other comprehensive loss, net of tax, consisted of the following:


	June 30, 2021		December 31, 2020
Fair value of interest rate swaps, net of tax	$	(10,066)	$	(14,446)
Cumulative foreign currency translation adjustment	(11,459)		(11,536)
Accumulated other comprehensive loss, net of tax	$	(21,525)	$	(25,982)

5. Inventories


	June 30, 2021		December 31, 2020
Petroleum and related products	$	199,074	$	248,977
Coal	952		3,240
Natural gas	2,620		3,316
Inventories	$	202,646	$	255,533

6. Credit Agreement


	June 30, 2021		December 31, 2020
Working capital facilities	$	246,598	$	358,685
Acquisition facility	377,400		382,400
Total credit agreement	623,998		741,085
Less: current portion of working capital facilities	(246,598)		(358,685)
Long-term portion	$	377,400	$	382,400

On May 11, 2021, Sprague Operating Resources LLC (the “U.S. Borrower”) and Kildair Service ULC (the “Canadian Borrower” and, together with the U.S. Borrower, the “Borrowers”), wholly owned subsidiaries of the Partnership, entered into a first amendment (the “First Amendment”) to the second amended and restated credit agreement dated as of May 19, 2020 (the "Original Credit Agreement" the Original Credit Agreement as amended by the First Amendment, the “Credit Agreement"). Upon the effective date, the First Amendment increased the acquisition facility from $430 million to $450 million and was accounted for as a modification of a syndicated loan arrangement with partial extinguishment to the extent there was a decrease in the borrowing capacity on a creditor by creditor basis. Overall, the Credit Agreement matures on May 19, 2023. The Partnership and certain of its subsidiaries (the “Subsidiary Guarantors”) are guarantors of the obligations under the Credit Agreement. Obligations under the Credit Agreement are secured by substantially all of the assets of the Partnership, the Borrowers and the Subsidiary Guarantors (collectively, the “Loan Parties”).

As of June 30, 2021, the revolving credit facilities under the Credit Agreement contained, among other items, the following:

•A committed U.S. dollar revolving working capital facility of up to $465.0 million, subject to borrowing base limits, to be used for working capital loans and letters of credit;

•An uncommitted U.S. dollar revolving working capital facility of up to $200.0 million, subject to borrowing base limits and the sole discretion of the lenders, to be used for working capital loans and letters of credit;

•A multicurrency revolving working capital facility of up to $85.0 million, subject to borrowing base limits, to be used for working capital loans and letters of credit;

•A revolving acquisition facility of up to $450.0 million, subject to borrowing base limits, to be used for loans and letters of credit to fund capital expenditures and acquisitions and other general corporate purposes; and

•Subject to certain conditions, including the receipt of additional commitments from lenders, the ability to increase the U.S. dollar revolving working capital facility to up to $1.2 billion and the multicurrency revolving working capital facility to up to $320.0 million. Additionally, subject to certain conditions, the revolving acquisition facility may be increased to up to $750.0 million.

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Indebtedness under the Credit Agreement bears interest, at the Borrowers’ option, at a rate per annum equal to either (i) the Eurocurrency Rate (which is the LIBOR Rate for loans denominated in U.S. dollars and CDOR for loans denominated in Canadian dollars, in each case adjusted for certain regulatory costs, and in each case with a floor of 0.25%) for interest periods of one, two (solely with respect to Eurocurrency Rate loans denominated in Canadian dollars), three or six (solely with respect to Eurocurrency Rate loans denominated in U.S. dollars) months plus a specified margin or (ii) an alternate rate plus a specified margin.

For loans denominated in U.S. dollars, the alternate rate is the Base Rate which is the highest of (a) the U.S. Prime Rate as in effect from time to time, (b) the greater of the Federal Funds Effective Rate and the Overnight Bank Funding Rate as in effect from time to time plus 0.50% and (c) the one-month Eurocurrency Rate for U.S. dollars as in effect from time to time plus 1.00%.

For loans denominated in Canadian dollars, the alternate rate is the Prime Rate which is the higher of (a) the Canadian Prime Rate as in effect from time to time and (b) the one-month Eurocurrency Rate for U.S. dollars as in effect from time to time plus 1.00%.

The specified margins for the working capital revolving facilities vary based on the utilization of the working capital facilities as a whole, measured on a quarterly basis. The specified margin for (x) the committed U.S. dollar revolving working capital facility range from 1.00% to 1.50% for loans bearing interest at the Base Rate and from 2.00% to 2.50% for loans bearing interest at the Eurocurrency Rate, (y) the uncommitted U.S. dollar revolving working capital facility range from 0.75% to 1.25% for loans bearing interest at the Base Rate and 1.75% to 2.25% for loans bearing interest at the Eurocurrency Rate and (z) the multicurrency revolving working capital facility range from 1.00% to 1.50% for loans bearing interest at the Base Rate and 2.00% to 2.50% for loans bearing interest at the Eurocurrency Rate.

The specified margin for the revolving acquisition facility varies based on the consolidated total leverage of the Loan Parties. The specified margin for the revolving acquisition facility range from 1.25% to 2.25% for loans bearing interest at the Base Rate and from 2.25% to 3.25% for loans bearing interest at the Eurocurrency Rate.

In addition, the Borrowers will incur a commitment fee on the unused portion of (x) the committed U.S. dollar revolving working capital facility and multicurrency revolving working capital facility ranging from 0.375% to 0.500% per annum and (y) the revolving acquisition facility at a rate ranging from 0.35% to 0.50% per annum. Overdue amounts bear interest at the applicable rates described above plus an additional margin of 2%.

The working capital facilities are subject to borrowing base reporting and as of June 30, 2021 and December 31, 2020, had a borrowing base of $384.4 million and $540.0 million, respectively. As of June 30, 2021 and December 31, 2020, outstanding letters of credit related to the working capital facilities were $16.0 million and $77.3 million, respectively. As of June 30, 2021 and December 31, 2020, outstanding letters of credit related to the acquisition facility were $13.9 million and $15.4 million, respectively. As of June 30, 2021, excess availability under the working capital facilities was $121.8 million and excess availability under the acquisition facility was $58.7 million.

The weighted average interest rate was 3.0% at both June 30, 2021 and December 31, 2020. No amounts are due under the Credit Agreement until the maturity date. However, the current portion at June 30, 2021 and December 31, 2020 represents the amounts of the working capital facility.

The Credit Agreement contains various covenants and restrictive provisions that, among other things, prohibit the Partnership from making distributions to unitholders if any event of default occurs or would result from the distribution or if the Loan Parties would not be in pro forma compliance with the financial covenants after giving effect to the distribution. In addition, the Credit Agreement contains various covenants that are usual and customary for a financing of this type, size and purpose, including, but not limited to, covenants that require the Loan Parties to maintain: a minimum consolidated EBITDA-to fixed-charge ratio, a minimum consolidated net working capital amount and a maximum consolidated total leverage-to-EBITDA ratio. The Credit Agreement also limits the Loan Parties ability to incur debt, grant liens, make certain investments or acquisitions, enter into affiliate transactions and dispose of assets. The Partnership was in compliance with the covenants under the Credit Agreement at June 30, 2021.

The Credit Agreement also contains events of default that are usual and customary for a financing of this type, size and purpose including, among others, non-payment of principal, interest or fees, violation of certain covenants, material inaccuracy of representations and warranties, bankruptcy and insolvency events, cross-payment default and cross-acceleration, material judgments and events constituting a change of control. If an event of default exists under the Credit Agreement, the lenders will

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be able to terminate the lending commitments, accelerate the maturity of the Credit Agreement and exercise other rights and remedies with respect to the collateral.

7. Related Party Transactions

The General Partner charges the Partnership for the reimbursements of employee costs and related employee benefits and other overhead costs supporting the Partnership’s operations which amounted to $20.2 million and $21.0 million for the three months ended June 30, 2021 and 2020, and $46.5 million and $44.5 million for the six months ended June 30, 2021 and 2020, respectively. Through the General Partner, the Partnership also participates in the Sponsor’s pension and other post-retirement benefits. At June 30, 2021 and December 31, 2020, total amounts due to the General Partner with respect to these benefits and overhead costs were $7.8 million and $13.7 million, respectively.

During the three and six months ended June 30, 2021, the Partnership recorded tank use and storage fee revenue of $0.2 million and $0.7 million, respectively, from lease agreements entered into with Hartree, a related party. In addition, the Partnership made net inventory purchases from Hartree totaling $29.8 million and $97.8 million for the three and six months ended June 30, 2021, respectively. As of June 30, 2021, the Partnership had a receivable of $0.5 million from Hartree related to certain fees paid on their behalf.

8. Segment Reporting

The Partnership has four reportable segments that comprise the structure used by the chief operating decision makers (CEO and CFO) to make key operating decisions and assess performance. When establishing a reporting segment, the Partnership aggregates individual operating units that are in the same line of business and have similar economic characteristics. These reportable segments are refined products, natural gas, materials handling and other operations.

The Partnership's refined products segment purchases a variety of refined products, such as heating oil, diesel fuel, residual fuel oil, kerosene, jet fuel and gasoline (primarily from refining companies, trading organizations and producers), and sells them to its customers. The Partnership has wholesale customers who resell the refined products they purchase from the Partnership and commercial customers who consume the refined products they purchase. The Partnership’s wholesale customers consist of home heating oil retailers and diesel fuel and gasoline resellers. The Partnership’s commercial customers include federal and state agencies, municipalities, regional transit authorities, drill sites, large industrial companies, real estate management companies, hospitals, educational institutions and asphalt paving companies. The refined products reportable segment consists of two operating segments.

The Partnership's natural gas segment purchases natural gas from natural gas producers and trading companies and sells and manages distribution of natural gas to commercial and industrial customer locations across 13 states in the Northeast and Mid-Atlantic United States and Canada. The natural gas reportable segment consists of one operating segment.

The Partnership's materials handling segment offloads, stores, and prepares for delivery a variety of customer-owned products, including asphalt, clay slurry, salt, gypsum, crude oil, residual fuel oil, coal, petroleum coke, caustic soda, tallow, pulp and heavy equipment. These services are generally conducted under multi-year agreements as either fee-based activities or as leasing arrangements when the right to use an identified asset (such as storage tanks or storage locations) has been conveyed in the agreement. The materials handling reportable segment consists of two operating segments.

The Partnership's other operations segment primarily consists of the purchase, sale and distribution of coal, and commercial trucking activities unrelated to its refined products segment. Other operations are not reported separately as they represent less than 10% of consolidated net sales and adjusted gross margin. The other operations reporting segment consists of two operating segments.

The Partnership evaluates segment performance based on adjusted gross margin, a non-GAAP measure, which is net sales less cost of products sold (exclusive of depreciation and amortization) increased by unrealized hedging losses and decreased by unrealized hedging gains, in each case with respect to refined products and natural gas inventory, and natural gas transportation contracts.

Based on the way the business is managed, it is not reasonably possible for the Partnership to allocate the components of operating costs and expenses among the operating segments. There were no significant intersegment sales for any of the years presented below.

The Partnership had no single customer that accounted for more than 10% of total net sales for the three and six months ended June 30, 2021 and 2020, respectively. The Partnership’s foreign sales, primarily sales of refined products and natural gas

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to its customers in Canada, were $73.0 million and $34.2 million for the three months ended June 30, 2021 and 2020, respectively, and $139.2 million and $87.2 million for the six months ended June 30, 2021 and 2020, respectively.

Summarized financial information for the Partnership's reportable segments is presented in the table below:


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Net sales:
Refined products	$	589,142	$	292,889	$	1,505,342	$	1,134,831
Natural gas	51,360		47,988		153,935		143,766
Materials handling	12,725		12,974		24,771		28,531
Other operations	4,445		4,363		9,757		10,965
Net sales	$	657,672	$	358,214	$	1,693,805	$	1,318,093
Adjusted gross margin (1):
Refined products	$	27,165	$	52,861	$	78,198	$	88,650
Natural gas	(2,725)		(2,245)		38,364		27,542
Materials handling	12,694		12,895		24,770		28,476
Other operations	1,696		1,673		3,709		3,626
Adjusted gross margin	38,830		65,184		145,041		148,294
Reconciliation to operating income (2):
Add/(deduct):
Change in unrealized (loss) gain on inventory (3)	(5,369)		(32,326)		20,888		(18,775)
Change in unrealized value on natural gas transportation contracts (4)	(35,592)		123		(56,709)		13,322
Operating costs and expenses not allocated to operating segments:
Operating expenses	(19,148)		(18,471)		(38,379)		(39,283)
Selling, general and administrative	(16,719)		(18,923)		(41,958)		(38,956)
Depreciation and amortization	(8,258)		(8,518)		(16,741)		(17,115)
Other operating income	9,725		—		9,725		—
Operating (loss) income	(36,531)		(12,931)		21,867		47,487
Other income	—		64		2		64
Interest income	77		72		143		248
Interest expense	(8,587)		(10,788)		(17,402)		(22,074)
Income tax provision	(562)		(1,542)		(1,433)		(4,113)
Net (loss) income	$	(45,603)	$	(25,125)	$	3,177	$	21,612

(1)The Partnership trades, purchases, stores and sells energy commodities that experience market value fluctuations. To manage the Partnership’s underlying performance, including its physical and derivative positions, management utilizes adjusted gross margin, which is a non-GAAP financial measure. Adjusted gross margin is also used by external users of the Partnership’s consolidated financial statements to assess the Partnership’s economic results of operations and its commodity market value reporting to lenders. In determining adjusted gross margin, the Partnership adjusts its segment results for the impact of the changes in unrealized gains and losses with regard to refined products and natural gas inventory, and natural gas transportation contracts, which are not marked to market for the purpose of recording unrealized gains or losses in net income. These adjustments align the unrealized hedging gains and losses to the period in which the revenue from the sale of inventory, prepaid fixed forwards and the utilization of transportation contracts relating to those hedges is realized in net income. Adjusted gross margin has no impact on reported volumes or net sales.

(2)Reconciliation of adjusted gross margin to operating income, the most directly comparable GAAP measure.

(3)Inventory is valued at the lower of cost or net realizable value. The adjustment related to change in the unrealized gain on inventory which is not included in net income, represents the estimated difference between inventory valued at the lower of cost or net realizable value as compared to market values. The fair value of the derivatives the Partnership uses to economically hedge its inventory declines or appreciates in value as the value of the underlying inventory appreciates or declines, which creates unrealized hedging losses (gains) with respect to the derivatives that are included in net income.

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(4)Represents the Partnership’s estimate of the change in fair value of the natural gas transportation contracts which are not recorded in net income until the transportation is utilized in the future (i.e., when natural gas is delivered to the customer), as these contracts are executory contracts that do not qualify as derivatives. As the fair value of the natural gas transportation contracts decline or appreciate, the offsetting physical or financial derivative will also appreciate or decline creating unmatched unrealized hedging (gains) losses in net income.

Segment Assets

Due to the commingled nature and uses of the Partnership’s fixed assets, the Partnership does not track its fixed assets between its refined products and materials handling operating segments or its other operations. There are no significant fixed assets attributable to the natural gas reportable segment.

As of June 30, 2021, goodwill recorded for the refined products, natural gas, materials handling and other operations segments amounted to $71.4 million, $35.5 million, $6.9 million and $1.2 million, respectively.

9. Financial Instruments and Off-Balance Sheet Risk

As of June 30, 2021 and December 31, 2020, the carrying amounts of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities approximated fair value because of the short maturity of these instruments. As of June 30, 2021 and December 31, 2020, the carrying value of the Partnership’s margin deposits with brokers approximates fair value and consists of initial margin with futures transaction brokers, along with variation margin, which is paid or received on a daily basis, and is included in other current assets or other current liabilities. As of June 30, 2021 and December 31, 2020, the carrying value of the Partnership’s debt approximated fair value due to the variable interest nature of these instruments.

The following table presents financial assets and financial liabilities of the Partnership measured at fair value on a recurring basis:


	As of June 30, 2021
	Fair Value Measurement		Quoted Prices in Active Markets Level 1		Significant Other Observable Inputs Level 2		Significant Unobservable Inputs Level 3
Derivative assets:

Commodity fixed forwards	$	24,024	$	—	$	24,024	$	—
Futures, swaps and options	113,175		113,175		—		—
Commodity derivatives	137,199		113,175		24,024		—


Total derivative assets	$	137,199	$	113,175	$	24,024	$	—
Derivative liabilities:

Commodity fixed forwards	86,925		—		86,925		—
Futures, swaps and options	74,015		73,923		92		—
Commodity derivatives	160,940		73,923		87,017		—
Interest rate swaps	10,146		—		10,146		—

Total derivative liabilities	$	171,086	$	73,923	$	97,163	$	—

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	As of December 31, 2020
	Fair Value Measurement		Quoted Prices in Active Markets Level 1		Significant Other Observable Inputs Level 2		Significant Unobservable Inputs Level 3
Derivative assets:
Commodity fixed forwards	$	64,514	$	—	$	64,514	$	—
Futures, swaps and options	101,464		101,464		—		—
Commodity derivatives	165,978		101,464		64,514		—


Total derivative assets	$	165,978	$	101,464	$	64,514	$	—
Derivative liabilities:

Commodity fixed forwards	25,973		—		25,973		—
Futures, swaps and options	133,809		133,743		66		—
Commodity derivatives	159,782		133,743		26,039		—
Interest rate swaps	14,559		—		14,559		—
Currency swaps	4		—		4		—
Total derivative liabilities	$	174,345	$	133,743	$	40,602	$	—

Commodity Derivative Instruments

The Partnership utilizes derivative instruments consisting of futures contracts, forward contracts, swaps, options and other derivatives individually or in combination, to mitigate its exposure to fluctuations in prices of refined petroleum products and natural gas. The use of these derivative instruments within the Partnership's risk management policy may, on a limited basis, generate gains or losses from changes in market prices. The Partnership enters into futures and over-the-counter (“OTC”) transactions either on regulated exchanges or in the OTC market. Futures contracts are exchange-traded contractual commitments to either receive or deliver a standard amount or value of a commodity at a specified future date and price, with some futures contracts based on cash settlement rather than a delivery requirement. Futures exchanges typically require margin deposits as security. OTC contracts, which may or may not require margin deposits as security, involve parties that have agreed either to exchange cash payments or deliver or receive the underlying commodity at a specified future date and price. The Partnership posts initial margin with futures transaction brokers, along with variation margin, which is paid or received on a daily basis, and is included in other current assets or other current liabilities. In addition, the Partnership may either pay or receive margin based upon exposure with counterparties. Payments made by the Partnership are included in other current assets, whereas payments received by the Partnership are included in accrued liabilities. Substantially of all of the Partnership’s commodity derivative contracts outstanding as of June 30, 2021 will settle prior to December 31, 2022.

The Partnership enters into some master netting arrangements to mitigate credit risk with significant counterparties. Master netting arrangements are standardized contracts that govern all specified transactions with the same counterparty and allow the Partnership to terminate all contracts upon occurrence of certain events, such as a counterparty’s default. The Partnership has elected not to offset the fair value of its derivatives, even where these arrangements provide the right to do so.

The Partnership’s derivative instruments are recorded at fair value, with changes in fair value recognized in net income each period. The Partnership’s fair value measurements are determined using the market approach and includes non-performance risk and time value of money considerations. Counterparty credit is considered for receivable balances, and the Partnership’s credit is considered for payable balances.

The Partnership determines fair value based on a hierarchy for the inputs used to measure the fair value of financial assets and liabilities based on the source of the input, which generally range from quoted prices for identical instruments in a principal trading market (Level 1) to estimates determined using significant unobservable inputs (Level 3). Multiple inputs may be used to measure fair value; however, the level of fair value is based on the lowest significant input level within this fair value hierarchy.

Details on the methods and assumptions used to determine the fair values are as follows:

Fair value measurements based on Level 1 inputs: Measurements that are most observable and are based on quoted prices of identical instruments obtained from the principal markets in which they are traded. Closing prices are both readily available and representative of fair value. Market transactions occur with sufficient frequency and volume to assure liquidity.

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Fair value measurements based on Level 2 inputs: Measurements derived indirectly from observable inputs or from quoted prices from markets that are less liquid are considered Level 2. Measurements based on Level 2 inputs include OTC derivative instruments that are priced on an exchange traded curve, but have contractual terms that are not identical to exchange traded contracts. The Partnership utilizes fair value measurements based on Level 2 inputs for its fixed forward contracts, over-the-counter commodity price swaps, interest rate swaps and forward currency contracts.

Fair value measurements based on Level 3 inputs: Measurements that are least observable are estimated from significant unobservable inputs determined from sources with little or no market activity for comparable contracts or for positions with longer durations.

The Partnership does not offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) against the fair value of derivative instruments executed with the same counterparty under the same master netting arrangement. The Partnership had no right to reclaim or obligation to return cash collateral as of June 30, 2021 and December 31, 2020.

The Partnership enters into derivative contracts with counterparties, some of which are subject to master netting arrangements, which allow net settlements under certain conditions. The Partnership presents derivatives at gross fair values in the Condensed Consolidated Balance Sheets. The maximum amount of loss due to credit risk that the Partnership would incur if its counterparties failed completely to perform according to the terms of the contracts, based on the net fair value of these financial instruments, exclusive of cash collateral, was $63.9 million at June 30, 2021.

Information related to these offsetting arrangements is set forth below:


	As of June 30, 2021
			Gross Amount Not Offset in the Balance Sheet
	Gross Amount of Assets/Liabilities in the Balance Sheet		Financial Instruments		Cash Collateral Posted		Net Amount
Commodity derivative assets	$	137,199	$	(73,309)	$	(32,179)	$	31,711


Fair value of derivative assets	$	137,199	$	(73,309)	$	(32,179)	$	31,711

Commodity derivative liabilities	$	(160,940)	$	73,309	$	2,472	$	(85,159)
Interest rate swap derivative liabilities	(10,146)		—		—		(10,146)

Fair value of derivative liabilities	$	(171,086)	$	73,309	$	2,472	$	(95,305)


	As of December 31, 2020
			Gross Amount Not Offset in the Balance Sheet
	Gross Amount of Assets/Liabilities in the Balance Sheet		Financial Instruments		Cash Collateral Posted		Net Amount
Commodity derivative assets	$	165,978	$	(102,736)	$	—	$	63,242


Fair value of derivative assets	$	165,978	$	(102,736)	$	—	$	63,242

Commodity derivative liabilities	$	(159,782)	$	102,736	$	32,488	$	(24,558)
Interest rate swap derivative liabilities	(14,559)		—		—		(14,559)
Currency swaps derivative liabilities	(4)		—		—		(4)
Fair value of derivative liabilities	$	(174,345)	$	102,736	$	32,488	$	(39,121)

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The following table presents total realized and unrealized gains (losses) on derivative instruments utilized for commodity risk management purposes included in cost of products sold (exclusive of depreciation and amortization):


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Refined products contracts	$	(19,503)	$	(8,869)	$	(39,277)	$	57,336
Natural gas contracts	(34,447)		3,332		(33,138)		39,345
Total	$	(53,950)	$	(5,537)	$	(72,415)	$	96,681

There were no discretionary trading activities for the three and six months ended June 30, 2021 and 2020. The following table presents gross volume of commodity derivative instruments outstanding for the periods indicated:


	As of June 30, 2021		As of December 31, 2020
	Refined Products (Barrels)	Natural Gas (MMBtus)	Refined Products (Barrels)	Natural Gas (MMBtus)
Long contracts	5,539	161,652	12,736	172,274
Short contracts	(7,816)	(83,840)	(16,825)	(86,913)

Interest Rate Derivatives

The Partnership has entered into interest rate swaps to manage its exposure to changes in interest rates on its Credit Agreement. The Partnership’s interest rate swaps hedge the actual and forecasted LIBOR borrowings and have been designated as cash flow hedges. Counterparties to the Partnership’s interest rate swaps are large multinational banks and the Partnership does not believe there is a material risk of counterparty non-performance. The Partnership expects to continue to utilize interest rate swaps to hedge cash flow risk and to manage its exposure to LIBOR interest rates or its replaced equivalent for the foreseeable future.

The Partnership's interest rate swap agreements outstanding as of June 30, 2021 were as follows:


Beginning	Ending	Notional Amount

January 2021	January 2022	$	300,000


April 2021	April 2022	$	25,000
January 2022	January 2023	$	250,000
April 2022	April 2023	$	25,000
January 2023	January 2024	$	250,000
January 2024	January 2025	$	50,000

The Partnership records unrealized gains and losses on its interest rate swaps as a component of accumulated other comprehensive loss, net of tax, which is reclassified to earnings as interest expense when the payments are made. As of June 30, 2021, the amount of unrealized losses, net of tax, expected to be reclassified to earnings during the following twelve-month period was $5.4 million.

10. Commitments and Contingencies

Legal, Environmental and Other Proceedings

The Partnership is subject to a tax on sales made in Quebec from product it imports into the province. During an audit by the Quebec Energy Board (QEB) of the annual filings, the Partnership initiated legal action seeking a declaration to limit the applicability of the tax to direct imports, as well as the periods subject to review. Since filing this legal action in June 2018, the Partnership has been assessed $7.9 million of tax, including interest and penalties, for the period of 2007 to 2020. Similarly, since the filing, the Partnership has been assessed $10.2 million, including a 15% penalty and interest, from the Ministry of the Environment, and the Fight Against Climate Change (known as MELCC) under separate regulation that was in effect for the period from 2007 through 2014. The Partnership is disputing this assessment on the same basis as set out in the QEB legal

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action described above. The Partnership has accrued an amount which it believes to be a reasonable estimate of the low end of a range of loss related to these matters and such amount is not material to the consolidated financial statements.

On September 14, 2020, a purported class action complaint was filed against Sprague Operating Resources, LLC ("SOR"), one of the Partnership’s subsidiaries, in the U.S. District Court for the District of Rhode Island. The complaint, since amended, alleges causes of action for private nuisance, public nuisance, and negligence, each based on emission impacts to nearby occupants from the Partnership’s oil and natural gas facility located in Providence, Rhode Island. The complaint also alleges that the amount in controversy exceeds $5.0 million. At this early stage in the litigation, the Partnership cannot predict whether the plaintiff will succeed in getting the court to certify a class. Based upon the information currently available to it, the Partnership believes that the complaint is without merit and intends to vigorously defend against it.

In May 2021, the New York City Department of Citywide Administrative Services (DCAS) initiated legal action against SOR, alleging that the SOR failed to pay the city $8.5 million in biodiesel tax credits for product purchased for the period of 2017 through 2019. SOR is disputing the claim and the Partnership has accrued an amount which it believes to be a reasonable estimate of the low end of a range of loss related to this matter and such amount is not material to the consolidated financial statements.

The Partnership is involved in other various lawsuits, other proceedings and environmental matters, all of which arose in the normal course of business. The Partnership believes, based upon its examination of currently available information, its experience to date, and advice from legal counsel, that the individual and aggregate liabilities resulting from the resolution of these contingent matters will not have a material adverse impact on the Partnership’s consolidated results of operations, financial position or cash flows.

11. Equity and Equity-Based Compensation

Equity Awards - Performance-based Phantom Units

Prior to March 5, 2021, the board of directors of the General Partner granted performance-based phantom unit awards to key employees that vested at the end of a performance period (generally three years). Phantom unit awards granted since 2016 include a performance criteria that considers Sprague Holdings operating cash flow, as defined ("OCF"), over a three year period. The number of common units that may be received in settlement of each phantom unit award can range between 0 and 200% of the number of phantom units granted based on the level of OCF achieved during the vesting period. These awards are equity awards with performance and service conditions which result in compensation cost being recognized over the requisite service period once payment is determined to be probable. Compensation expense is estimated each reporting period by multiplying the number of common units underlying such awards that, based on the Partnership's estimate of OCF, are probable to vest, by the grant-date fair value of the award and is recognized over the requisite service period using the straight-line method. The number of units that the Partnership estimates are probable to vest could change over the vesting period. Any such change in estimate is recognized as a cumulative adjustment calculated as if the new estimate had been in effect from the grant date. The Partnership's long-term incentive phantom unit awards include tandem distribution equivalent rights ("DERs") which entitle the participant to a cash payment upon vesting that is equal to any cash distribution paid on a common unit between the grant date and the date the phantom units were settled.

Effective March 5, 2021, the board of directors used its discretion to terminate all phantom unit awards granted in 2018, 2019 and 2020. In consideration for this termination, the board of directors paid a higher 2020 cash bonus and issued vested common units to each of the Partnership's Named Executive Officers and certain other employees as well as cash bonuses to all employees. The 2020 cash bonus amounts were expensed during the year ended December 31, 2020 and accrued for as of December 31, 2020. The Company accounted for the cancellation of the previously outstanding phantom unit awards and the issuance of the vest units during the quarter ended March 31, 2021 as a modification which resulted in a net immaterial impact to unit-based compensation expense during the quarter.

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The following table presents a summary of the Partnership’s phantom unit awards that were cancelled during the six months ended June 30, 2021:


	2020 Awards			2019 Awards			2018 Awards
	Units	Weighted Average Grant Date Fair Value (per unit)		Units	Weighted Average Grant Date Fair Value (per unit)		Units	Weighted Average Grant Date Fair Value (per unit)
Nonvested at December 31, 2020	173,250	$	15.16	155,337	$	15.04	107,450	$	23.30

Cancelled	(173,250)	(15.16)		(155,337)	(15.04)		(107,450)	(23.30)

Nonvested at June 30, 2021	—	$	—	—	$	—	—	$	—

Unit-based compensation expense for the six months ended June 30, 2021 was $0.2 million as compared to $1.3 million for the six months ended June 30, 2020.

Unit-based compensation is included in selling, general and administrative expenses. The Partnership didn't have any unrecognized compensation cost related to performance-based phantom units as of June 30, 2021 as a result of the termination of units.

Equity - Changes in Partnership Units

The following table provides information with respect to changes in the Partnership’s units:


	Common Units
	Public	Affiliated
Balance as of December 31, 2019	10,641,561	12,106,348
Units issued in connection with employee bonus	61,782	—
Distribution paid in units	—	121,150
Director vested awards	15,464	—
Units purchased in Private Placement	(723,738)	723,738
Balance as of December 31, 2020	9,995,069	12,951,236
Units issued in connection with employee bonus	172,702	—

Units issued in conjunction with IDR Reset Election	—	3,107,248
Increase in affiliated units as a result of acquisition by Hartree Partners, LP	(2,115,365)	2,115,365
Balance as of June 30, 2021	8,052,406	18,173,849

IDR Reset Election

On February 11, 2021, Sprague Holdings provided notice to the Partnership that Sprague Holdings had made the IDR Reset Election. Pursuant to the IDR Reset Election, Sprague Holdings relinquished the right to receive incentive distribution payments based on the minimum quarterly and target cash distribution levels set at the time of the Partnership’s initial public offering and the Partnership issued 3,107,248 common units to Sprague Holdings. Pursuant to the IDR Reset Election, the minimum quarterly distribution amount increased from $0.4125 per common unit per quarter to $0.6675 per common unit per quarter and the levels at which the incentive distribution rights participate in distributions were reset at higher amounts based on then-current common unit distribution rates and a formula in the Partnership Agreement. The IDR Reset Election was effective on March 5, 2021.

12. Earnings Per Unit

The Partnership has identified the IDRs as participating securities and uses the two-class method when calculating the net income per unit applicable to limited partners. Earnings per unit applicable to limited partners is computed by dividing limited partners’ interest in net income, after deducting any incentive distributions, by the weighted-average number of outstanding common units. The Partnership’s net income is allocated to the limited partners in accordance with their respective ownership percentages, after giving effect to priority income allocations for incentive distributions, which are declared and paid following

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the close of each quarter. Earnings in excess of distributions are allocated to the limited partners based on their respective ownership interests. Diluted earnings per unit includes the effects of potentially dilutive units on the Partnership’s common units, consisting of unvested phantom units. Effective March 5, 2021, there is no dilutive effect for 2021 due to the termination of all phantom units as described in Note 11.

Payments made to the Partnership’s unitholders are determined in relation to actual distributions declared and are not based on the net income allocations used in the calculation of earnings per unit.

The table below shows the weighted average common units outstanding used to compute net income per common unit for the periods indicated.


	Three Months Ended June 30,		Six Months Ended June 30,
	2021	2020	2021	2020
Weighted average limited partner common units - basic	26,226,255	22,922,902	25,066,494	22,871,943
Dilutive effect of unvested phantom units	—	—	—	65,330
Weighted average limited partner common units - dilutive	26,226,255	22,922,902	25,066,494	22,937,273

13. Partnership Distributions

The Partnership's partnership agreement sets forth the calculation to be used to determine the amount and priority of cash distributions that the common unitholders will receive.

Cash distributions for the periods indicated were as follows:


Quarter Ended	Payment Date	Per Unit	Common		IDR		Total
December 31, 2020	February 10, 2021	$0.6675	$	15,317	$	2,074	$	17,391
March 31, 2021	May 10, 2021	$0.6675	$	17,506	$	—	$	17,506

In addition, on July 23, 2021, the Partnership declared a cash distribution for the three months ended June 30, 2021, of $0.6675 per unit, totaling $17.5 million. Such distribution is to be paid on August 9, 2021, to unitholders of record on August 3, 2021.

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

As used in this Quarterly Report on Form 10-Q ("Quarterly Report"), unless the context otherwise requires, prior to May 28, 2021, references to "Sprague Resources," the "Partnership," "we," "our," "us," or like terms, refer to Sprague Resources LP and its subsidiaries; references to our "General Partner" refer to Sprague Resources GP LLC; references to "Axel Johnson" or the "Sponsor" refer to Axel Johnson Inc. and its controlled affiliates, collectively, other than Sprague Resources, its subsidiaries and its General Partner; and references to "Sprague Holdings" refer to Sprague Resources Holdings LLC, a wholly owned subsidiary of Axel Johnson and the owner of our General Partner. Prior to May 28, 2021, our General Partner was a wholly owned subsidiary of Axel Johnson.

As used in this Quarterly Report on Form 10-Q ("Quarterly Report"), unless the context otherwise requires, effective May 28, 2021, references to "Sprague Resources," the "Partnership," "we," "our," "us," or like terms, refer to Sprague Resources LP and its subsidiaries; references to our "General Partner" refer to Sprague Resources GP LLC; references to "Hartree" or the "Sponsor" refer to Hartree Partners, LP, other than Sprague Resources, its subsidiaries and its General Partner; and references to "Sprague Holdings" refer to Sprague HP Holdings, LLC, a wholly owned subsidiary of Hartree and the owner of our General Partner. Effective May 28, 2021 our General Partner is a wholly owned subsidiary of Hartree.

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report and any information incorporated by reference, contains statements that we believe are “forward-looking statements”. Forward looking statements are statements that express our belief, expectations, estimates, or intentions, as well as those statements we make that are not statements of historical fact, including, among other things, statements relating to the Transaction (as defined below) and the expected benefits thereof. Forward-looking statements provide our current expectations and contain projections of results of operations, or financial condition, and/ or forecasts of future events. Words such as “may”, “assume”, “forecast”, “position”, “seek”, “predict”, “strategy”, “expect”, “intend”, “plan”, “estimate”, “anticipate”, “believe”, “project”, “budget”, “outlook”, “potential”, “will”, “could”, “should”, or “continue”, and similar expressions are used to identify forward-looking statements. They can be affected by assumptions used or by known or unknown risks or uncertainties which could cause our actual results to differ materially from those contained in any forward-looking statement. Consequently, no forward-looking statements can be guaranteed. You are cautioned not to place undue reliance on any forward-looking statements.

Factors that could cause actual results to differ from those in the forward-looking statements include, but are not limited to: (i) changes in federal, state, local, and foreign laws or regulations including those that permit us to be treated as a partnership for federal income tax purposes, those that govern environmental protection and those that regulate the sale of our products to our customers; (ii) changes in the marketplace for our products or services resulting from events such as dramatic changes in commodity prices, increased competition, increased energy conservation, increased use of alternative fuels and new technologies, changes in local, domestic or international inventory levels, seasonality, changes in supply, weather and logistics disruptions, or general reductions in demand; (iii) security risks including terrorism and cyber-risk, (iv) adverse weather conditions, particularly warmer winter seasons and cooler summer seasons, climate change, environmental releases and natural disasters; (v) adverse local, regional, national, or international economic conditions, including but not limited to, public health crises that reduce economic activity, affect the demand for travel (public and private), as well as impacting costs of operation and availability of supply (including the coronavirus COVID-19 outbreak), unfavorable capital market conditions and detrimental political developments such as the inability to move products between foreign locales and the United States; (vi) nonpayment or nonperformance by our customers or suppliers; (vii) shutdowns or interruptions at our terminals and storage assets or at the source points for the products we store or sell, disruptions in our labor force, as well as disruptions in our information technology systems; (viii) unanticipated capital expenditures in connection with the construction, repair, or replacement of our assets; (ix) our ability to integrate acquired assets with our existing assets and to realize anticipated cost savings and other efficiencies and benefits; and (x) our ability to successfully complete our organic growth and acquisition projects and/or to realize the anticipated financial and operational benefits. These are not all of the important factors that could cause actual results to differ materially from those expressed in our forward-looking statements. Other known or unpredictable factors could also have material adverse effects on future results. Consequently, all of the forward-looking statements made in this Quarterly Report are qualified by these cautionary statements, and we cannot assure you that actual results or developments that we anticipate will be realized or, even if realized, will have the expected consequences to or effect on us or our business or operations. In light of these risks, uncertainties and assumptions, the forward-looking events discussed in this Quarterly Report may not occur.

When considering these forward-looking statements, please note that we provide additional cautionary discussion of risks and uncertainties in our Annual Report on Form 10-K for the year ended December 31, 2020, as filed with the U.S. Securities and Exchange Commission (“SEC”) on March 4, 2021 (the “2020 Annual Report”), in Part I, Item 1A “Risk Factors”, in Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations”, and in Part II, Item 7A “Quantitative and Qualitative Disclosures About Market Risk”. In light of these risks, uncertainties and assumptions, the forward-looking events discussed in this Quarterly Report may not occur.

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Forward-looking statements contained in this Quarterly Report speak only as of the date of this Quarterly Report (or other date as specified in this Quarterly Report) or as of the date given if provided in another filing with the SEC. We undertake no obligation, and disclaim any obligation, to publicly update, review or revise any forward-looking statements to reflect events or circumstances after the date of such statements. All forward looking statements attributable to us or any person acting on our behalf are expressly qualified in their entirety by the cautionary statements contained or referred to in our existing and future periodic reports filed with the SEC.

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Overview

We are a Delaware limited partnership formed in June 2011 by Sprague Holdings and our General Partner. We engage in the purchase, storage, distribution and sale of refined products and natural gas, and provide storage and handling services for a broad range of materials. In October 2013, we became a publicly traded master limited partnership ("MLP") and our common units representing limited partner interests are listed on the New York Stock Exchange ("NYSE") under the ticker symbol “SRLP".

Our Predecessor was founded in 1870 as the Charles H. Sprague Company in Boston, Massachusetts; and, in 1905, the company opened the Penobscot Coal and Wharf Company, a tidewater terminal located in Searsport, Maine. By World War II, the company was operating eleven terminals and a fleet of two dozen vessels transporting coal and other products throughout the world. As fuel needs diversified in the United States, the company expanded its product offerings and invested in terminals, tankers, and product handling activities. In 1959, the company expanded its oil marketing activities via entry into the distillate oil market. In 1970, the company was sold to Royal Dutch Shell’s Asiatic Petroleum subsidiary; and, in 1972, Royal Dutch Shell sold the company to Axel Johnson Inc., a member of the Axel Johnson Group of Stockholm, Sweden.

We are one of the largest independent wholesale distributors of refined products in the Northeast United States based on aggregate terminal capacity. We own, operate and/or control a network of refined products and materials handling terminals and storage facilities predominantly located in the Northeast United States from New York to Maine and in Quebec, Canada that have a combined storage tank capacity of approximately 14.4 million barrels for refined products and other liquid materials, as well as approximately 2.0 million square feet of materials handling capacity. We also have access to approximately 40 third-party terminals in the Northeast United States through which we sell or distribute refined products pursuant to rack, exchange and throughput agreements.

We operate under four business segments: refined products, natural gas, materials handling and other operations. See Note 8 - Segment Reporting to our Condensed Consolidated Financial Statements for a presentation of financial results by reportable segment and see Part I, Item 2 Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations for a discussion of financial results by segment.

In our refined products segment we purchase a variety of refined products, such as heating oil, diesel fuel, residual fuel oil, kerosene, jet fuel and gasoline (primarily from refining companies, trading organizations and producers), and sell them to our customers. We have wholesale customers who resell the refined products we sell to them and commercial customers who consume the refined products directly. Our wholesale customers consist of approximately 800 home heating oil retailers and diesel fuel and gasoline resellers. Our commercial customers include federal and state agencies, municipalities, regional transit authorities, drill sites, large industrial companies, real estate management companies, hospitals, educational institutions, and asphalt paving companies. In addition, as a result of our acquisition of Coen Energy in 2017, our customers include businesses engaged in the development of natural gas resources in Pennsylvania and surrounding states.

In our natural gas segment we purchase natural gas from natural gas producers and trading companies and sell and distribute natural gas to approximately 15,000 commercial and industrial customer locations across 13 states in the Northeast and Mid-Atlantic United States and Canada.

Our materials handling segment is generally conducted under multi-year agreements as either fee-based activities or as leasing arrangements when the right to use an identified asset (such as storage tanks or storage locations) has been conveyed in the agreement. We offload, store and/or prepare for delivery a variety of customer-owned products, including asphalt, clay slurry, salt, gypsum, crude oil, residual fuel oil, coal, petroleum coke, caustic soda, tallow, pulp and heavy equipment. Historically, a majority of our materials handling activity has generated qualified income.

Our other operations segment primarily includes the marketing and distribution of coal conducted in our Portland, Maine terminal, and commercial trucking activity conducted by our Canadian subsidiary.

We take title to the products we sell in our refined products and natural gas segments. In order to manage our exposure to commodity price fluctuations, we use derivatives and forward contracts to maintain a position that is substantially balanced between product purchases and product sales. We do not take title to any of the products in our materials handling segment.

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Hartree Transaction

On April 20, 2021, the Partnership and Hartree Partner, LP ("Hartree") announced that Sprague Holdings entered into an agreement to sell to Sprague HP Holdings, LLC (a wholly-owned subsidiary of Hartree) the interest of Sprague Holdings in the General Partner, the incentive distribution rights and all of the common units representing limited partner interests that Sprague Holdings owned in the Partnership (the “Transaction”). The Transaction was completed and effective on May 28, 2021.

IDR Reset Election

On February 11, 2021, Sprague Holdings provided notice to Partnership that Sprague Holdings had made an IDR Reset Election, as defined in our partnership agreement. Pursuant to the IDR Reset Election, Sprague Holdings relinquished the right to receive incentive distribution payments based on the minimum quarterly and target cash distribution levels set at the time of the Partnership’s initial public offering and the Partnership issued 3,107,248 common units to Sprague Holdings. Pursuant to the IDR Reset Election, the minimum quarterly distribution amount increased from $0.4125 per common unit per quarter to $0.6675 per common unit per quarter and the levels at which the incentive distribution rights participate in distributions were reset at higher amounts based on then-current common unit distribution rates and a formula in our partnership agreement. The IDR Reset Election was effective on March 5, 2021.

As of June 30, 2021, our Sponsor, through its ownership of Sprague Holdings, owns 18,173,849 common units (consisting of the 16,058,484 common units purchased as part of the Transaction and 2,115,365 common units beneficially owned by Hartree prior to the consummation of the Transaction) representing an aggregate of 69.3% of the limited partner interest in the Partnership. As of June 30, 2021, Hartree Bulk Storage, LLC and HP Bulk Storage Manager, LLC, (uncontrolled affiliated of Hartree Partners LP) beneficially own an additional 1,375,000 common units which are included in the public units outstanding. Sprague Holdings also owns the General Partner, which in turn owns a non-economic interest in the Partnership. Sprague Holdings currently holds incentive distribution rights (“IDRs”) which entitle it to receive increasing percentages, up to a maximum of 50.0%, of the cash the Partnership distributes from distributable cash flow in excess of $0.7676 per unit per quarter ($0.4744 prior to the consummation of IDR Reset Election). The maximum IDR distribution of 50.0% does not include any distributions that Sprague Holdings may receive on any limited partner units that it owns.

COVID-19

The pandemic and associated impacts on economic activity had an adverse effect on the Partnership’s operating results for the quarterly period ended June 30, 2021, specifically, the Partnership has seen a decline in demand and related sales volume as large sectors of the global economy have been adversely impacted by the crisis. In response to these developments, the Partnership took swift action to ensure the safety of employees and other stakeholders, and initiated a number of initiatives relating to cost reduction, liquidity and operating efficiencies.

The Partnership makes estimates and assumptions that affect the reported amounts on these consolidated financial statements and accompanying notes as of the date of the financial statements. The Partnership assessed accounting estimates that require consideration of forecasted financial information, including, but not limited to, the allowance for credit losses, the carrying value of goodwill, intangible assets, and other long-lived assets. This assessment was conducted in the context of information reasonably available to the Partnership, as well as consideration of the future potential impacts of COVID-19 on the Partnership’s business as of June 30, 2021. While market conditions for our products and services have improved when compared to a year ago, the pandemic remains fluid, indicating that the full impact may not have been realized across our business and operations. The economic and operational landscape has been altered, and it is difficult to determine whether such changes are temporary or permanent, with challenges related to staffing, supply chain, and transportation globally. The Partnership continues to monitor the evolving impacts of COVID-19 and variants closely and respond to changing conditions.

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How Management Evaluates Our Results of Operations

Our management uses a variety of financial and operational measurements to analyze our performance. These measurements include: (1) adjusted EBITDA and adjusted gross margin, (2) operating expenses, (3) selling, general and administrative (or SG&A) expenses and (4) heating degree days.

EBITDA, adjusted EBITDA and adjusted gross margin used in this Quarterly Report are non-GAAP financial measures.

EBITDA and Adjusted EBITDA

Management believes that adjusted EBITDA is an aid in assessing repeatable operating performance that is not distorted by non-recurring items or market volatility and the ability of our assets to generate sufficient revenue, that when rendered to cash, will be available to pay interest on our indebtedness and make distributions to our unitholders.

We define EBITDA as net income before interest, income taxes, depreciation and amortization. We define adjusted EBITDA as EBITDA adjusted for the change in unrealized hedging gains (losses) with respect to refined products and natural gas inventory, and natural gas transportation contracts, adjusted for changes in the fair value of contingent consideration, and adjusted for the impact of acquisition related expenses.

EBITDA and adjusted EBITDA are used as supplemental financial measures by external users of our financial statements, such as investors, trade suppliers, research analysts and commercial banks to assess:

•The financial performance of our assets, operations and return on capital without regard to financing methods, capital structure or historical cost basis;

•The ability of our assets to generate sufficient revenue, that when rendered to cash, will be available to pay interest on our indebtedness and make distributions to our equity holders;

•Repeatable operating performance that is not distorted by non-recurring items or market volatility; and

•The viability of acquisitions and capital expenditure projects.

EBITDA and adjusted EBITDA are not prepared in accordance with GAAP and should not be considered alternatives to net income or operating income, or any other measure of financial performance presented in accordance with GAAP. EBITDA and adjusted EBITDA exclude some, but not all, items that affect net income and operating income.

The GAAP measure most directly comparable to EBITDA and adjusted EBITDA is net income. EBITDA and adjusted EBITDA should not be considered as alternatives to net income or cash provided by (used in) operating activities, or any other measure of financial performance or liquidity presented in accordance with GAAP. EBITDA and adjusted EBITDA are not presentations made in accordance with GAAP and have important limitations as analytical tools and should not be considered in isolation or as substitutes for analysis of our results as reported under GAAP. Because EBITDA and adjusted EBITDA exclude some, but not all, items that affect net income and are defined differently by different companies, our definitions of EBITDA and adjusted EBITDA may not be comparable to similarly titled measures of other companies.

We recognize that the usefulness of EBITDA and adjusted EBITDA as evaluative tools may have certain limitations, including:

•EBITDA and adjusted EBITDA do not include interest expense. Because we have borrowed money in order to finance our operations, interest expense is a necessary element of our costs and impacts our ability to generate profits and cash flows. Therefore, any measure that excludes interest expense may have material limitations;

•EBITDA and adjusted EBITDA do not include depreciation and amortization expense. Because capital assets, depreciation and amortization expense is a necessary element of our costs and ability to generate profits, any measure that excludes depreciation and amortization expense may have material limitations;

•EBITDA and adjusted EBITDA do not include provision for income taxes. Because the payment of income taxes is a necessary element of our costs, any measure that excludes income tax expense may have material limitations;

•EBITDA and adjusted EBITDA do not reflect capital expenditures or future requirements for capital expenditures or contractual commitments;

•EBITDA and adjusted EBITDA do not reflect changes in, or cash requirements for, working capital needs; and

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•EBITDA and adjusted EBITDA do not allow us to analyze the effect of certain recurring and non-recurring items that materially affect our net income or loss.

Adjusted Gross Margin

Management purchases, stores and sells energy commodities that experience market value fluctuations. To manage the Partnership’s underlying performance, including its physical and derivative positions, management utilizes adjusted gross margin. In determining adjusted gross margin, management adjusts its segment results for the impact of the changes in unrealized gains and losses with regard to refined products and natural gas inventory, and natural gas transportation contracts, which are not marked to market for the purpose of recording unrealized gains or losses in net income. Adjusted gross margin is also used by external users of our consolidated financial statements to assess our economic results of operations and our commodity market value reporting to lenders.

We define adjusted gross margin as net sales less cost of products sold (exclusive of depreciation and amortization) adjusted for the impact of the changes in unrealized gains and losses with regard to refined products and natural gas inventory, and natural gas transportation contracts, which are not marked to market for the purpose of recording unrealized gains or losses in net income. Adjusted gross margin has no impact on reported volumes or net sales.

Adjusted gross margin is used as a supplemental financial measure by management to describe our operations and economic performance to investors, trade suppliers, research analysts and commercial banks to assess:

•The economic results of our operations;

•The market value of our inventory and natural gas transportation contracts for financial reporting to our lenders, as well as for borrowing base purposes; and

•Repeatable operating performance that is not distorted by non-recurring items or market volatility.

Adjusted gross margin is not prepared in accordance with GAAP and should not be considered as an alternative to net income or operating income or any other measure of financial performance presented in accordance with GAAP.

We define adjusted unit gross margin as adjusted gross margin divided by units sold, as expressed in gallons for refined products and in MMBtus for natural gas.

For a reconciliation of adjusted gross margin and adjusted EBITDA to the GAAP measures most directly comparable, see the reconciliation tables included in "Results of Operations." See Note 8 - Segment Reporting to our Condensed Consolidated Financial Statements for a presentation of our financial results by reportable segment.

Management evaluates our segment performance based on adjusted gross margin. Based on the way we manage our business, it is not reasonably possible for us to allocate the components of operating expenses, selling, general and administrative expenses and depreciation and amortization among the operating segments.

Operating Expenses

Operating expenses are costs associated with the operation of the terminals and truck fleet used in our business. Employee wages, pension and 401(k) plan expenses, boiler fuel, repairs and maintenance, utilities, insurance, property taxes, services and lease payments comprise the most significant portions of our operating expenses. Employee wages and related employee expenses included in our operating expenses are incurred on our behalf by our General Partner and reimbursed by us. These expenses remain relatively stable independent of the volumes through our system but can fluctuate depending on the activities performed during a specific period.

Selling, General and Administrative Expenses

Selling, general and administrative expenses ("SG&A") include employee salaries and benefits, discretionary bonus, marketing costs, corporate overhead, professional fees, information technology and office space expenses. Employee wages, related employee expenses and certain rental costs included in our SG&A expenses are incurred on our behalf by our General Partner and reimbursed by us.

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Heating Degree Days

A “degree day” is an industry measurement of temperature designed to evaluate energy demand and consumption. Degree days are based on how much 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 over the course of a year and can be compared to a monthly or a long-term average ("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 archived by the National Climate Data Center. In order to incorporate more recent average information and to better reflect the geographic locations of our customer base, we report degree day information for Boston and New York City (weighted equally) with a historical average for the same geographic locations over the previous ten-year period.

Hedging Activities

We hedge our inventory within the guidelines set in our risk management policies. In a rising commodity price environment, the market value of our inventory will generally be higher than the cost of our inventory. For GAAP purposes, we are required to value our inventory at the lower of cost or net realizable value. The hedges on this inventory will lose value as the value of the underlying commodity rises, creating hedging losses. Because we do not utilize hedge accounting, GAAP requires us to record those hedging losses in our income statements. In contrast, in a declining commodity price market we generally incur hedging gains. GAAP requires us to record those hedging gains in our income statements.

The refined products inventory market valuation is calculated using daily independent bulk market price assessments from major pricing services (either Platts or Argus). These third-party price assessments are primarily based in large, liquid trading hubs including but not limited to, New York Harbor (NYH) or US Gulf Coast (USGC), with our inventory values determined after adjusting these prices to the various inventory locations by adding expected cost differentials (primarily freight) compared to one of these supply sources. Our natural gas inventory is limited, with the valuation updated monthly based on the volume and prices at the corresponding inventory locations. The prices are based on the most applicable monthly Inside FERC, or IFERC, assessments published by Platts near the beginning of the following month.

Similarly, we can hedge our natural gas transportation assets (i.e., pipeline capacity) within the guidelines set in our risk management policy. Although we do not own any natural gas pipelines, we secure the use of pipeline capacity to support our natural gas requirements by either leasing capacity over a pipeline for a defined time period or by being assigned capacity from a local distribution company for supplying our customers. As the spread between the price of gas between the origin and delivery point widens (assuming the value exceeds the fixed charge of the transportation), the market value of the natural gas transportation contracts assets will typically increase. If the market value of the transportation asset exceeds costs, we may seek to hedge or “lock in” the value of the transportation asset for future periods using available financial instruments. For GAAP purposes, the increase in value of the natural gas transportation assets is not recorded as income in the income statements until the transportation is utilized in the future (i.e., when natural gas is delivered to our customer). If the value of the natural gas transportation assets increase, the hedges on the natural gas transportation assets lose value, creating hedging losses in our income statements. The natural gas transportation assets market value is calculated daily based on the volume and prices at the corresponding pipeline locations. The daily prices are based on trader assessed quotes which represent observable transactions in the market place, with the end-month valuations primarily based on Platts prices where available or adding a location differential to the price assessment of a more liquid location.

As described above, pursuant to GAAP, we value our commodity derivative hedges at the end of each reporting period based on current commodity prices and record hedging gains or losses, as appropriate. Also as described above, and pursuant to GAAP, our refined products and natural gas inventory and natural gas transportation contract rights, to which the commodity derivative hedges relate, are not marked to market for the purpose of recording gains or losses. In measuring our operating performance, we rely on our GAAP financial results, but we also find it useful to adjust those numbers to reflect the changes in unrealized gains and losses with regard to refined products and natural gas inventory, and natural gas transportation contracts. By making such adjustments, as reflected in adjusted gross margin and adjusted EBITDA, we believe that we are able to align more closely hedging gains and losses to the period in which the revenue from the sale of inventory and income from transportation contracts relating to those hedges is realized.

Trends and Factors that Impact our Business

In addition to the other information set forth in this report, please refer to our 2020 Annual Report for a discussion of the trends and factors that impact our business.

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Results of Operations

Our current and future results of operations may not be comparable to our historical results of operations. Our results of operations may be impacted by, among other things, swings in commodity prices, primarily in refined products and natural gas, and acquisitions or dispositions. We use economic hedges to minimize the impact of changing prices on refined products and natural gas inventory. As a result, commodity price increases at the end of a period can create lower gross margins as the economic hedges, or derivatives, for such inventory may lose value, whereas an increase in the value of such inventory is disregarded for GAAP financial reporting purposes and recorded at the lower of cost or net realizable value. Please read “How Management Evaluates Our Results of Operations.”

The following tables set forth information regarding our results of operations for the periods presented:



	Three Months Ended June 30,				Increase/(Decrease)
	2021		2020		$		%
	(in thousands)
Net sales	$	657,672	$	358,214	$	299,458	84	%
Cost of products sold (exclusive of depreciation and amortization)	659,803		325,233		334,570		103	%
Operating expenses	19,148		18,471		677		4	%
Selling, general and administrative	16,719		18,923		(2,204)		(12)	%
Depreciation and amortization	8,258		8,518		(260)		(3)	%
Total operating costs and expenses	703,928		371,145		332,783		90	%
Other operating income	9,725		—		9,725		N/A
Operating loss	(36,531)		(12,931)		(23,600)		183	%
Other income	—		64		(64)		(100)	%
Interest income	77		72		5		7	%
Interest expense	(8,587)		(10,788)		2,201		(20)	%
Loss before income taxes	(45,041)		(23,583)		(21,458)		91	%
Income tax provision	(562)		(1,542)		980		(64)	%
Net loss	$	(45,603)	$	(25,125)	$	(20,478)	82	%



	Six Months Ended June 30,				Increase/(Decrease)
	2021		2020		$		%
	(in thousands)
Net sales	$	1,693,805	$	1,318,093	$	375,712	29	%
Cost of products sold (exclusive of depreciation and amortization)	1,584,585		1,175,252		409,333		35	%
Operating expenses	38,379		39,283		(904)		(2)	%
Selling, general and administrative	41,958		38,956		3,002		8	%
Depreciation and amortization	16,741		17,115		(374)		(2)	%
Total operating costs and expenses	1,681,663		1,270,606		411,057		32	%
Other operating income	9,725		—		9,725		N/A
Operating income	21,867		47,487		(25,620)		(54)	%
Other income	2		64		(62)		(97)	%
Interest income	143		248		(105)		(42)	%
Interest expense	(17,402)		(22,074)		4,672		(21)	%
Income before income taxes	4,610		25,725		(21,115)		(82)	%
Income tax provision	(1,433)		(4,113)		2,680		(65)	%
Net income	$	3,177	$	21,612	$	(18,435)	(85)	%

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Reconciliation to Adjusted Gross Margin, EBITDA and Adjusted EBITDA

The following table sets forth a reconciliation of our consolidated operating income to our total adjusted gross margin, a non-GAAP measure, for the periods presented and a reconciliation of our consolidated net income to EBITDA and Adjusted EBITDA, non-GAAP measures, for the periods presented. See above “Management’s Discussion and Analysis of Financial Condition and Results of Operations - How Management Evaluates Our Results of Operations - EBITDA and Adjusted EBITDA” of this report. The table below also presents information on weather conditions for the periods presented.


	Three Months Ended June 30,						Six Months Ended June 30,
	2021			2020			2021			2020
	(in thousands)
Reconciliation of Operating Income to Adjusted Gross Margin:
Operating (loss) income	$	(36,531)		$	(12,931)		$	21,867		$	47,487
Operating costs and expenses not allocated to operating segments:
Operating expenses	19,148			18,471			38,379			39,283
Selling, general and administrative	16,719			18,923			41,958			38,956
Depreciation and amortization	8,258			8,518			16,741			17,115
Other operating income (7)	(9,725)			—			(9,727)			—
Add/(deduct):
Change in unrealized loss (gain) on inventory (1)	5,369			32,326			(20,888)			18,775
Change in unrealized value on natural gas transportation contracts (2)	35,592			(123)			56,711			(13,322)
Total adjusted gross margin (3):	$	38,830		$	65,184		$	145,041		$	148,294
Adjusted Gross Margin by Segment:
Refined products	$	27,165		$	52,861		$	78,198		$	88,650
Natural gas	(2,725)			(2,245)			38,364			27,542
Materials handling	12,694			12,895			24,770			28,476
Other operations	1,696			1,673			3,709			3,626
Total adjusted gross margin	$	38,830		$	65,184		$	145,041		$	148,294
Reconciliation of Net Income to Adjusted EBITDA
Net (loss) income	$	(45,603)		$	(25,125)		$	3,177		$	21,612
Add/(deduct):
Interest expense, net	8,510			10,716			17,259			21,826
Tax provision	562			1,542			1,433			4,113
Depreciation and amortization	8,258			8,518			16,741			17,115
EBITDA (3):	$	(28,273)		$	(4,349)		$	38,610		$	64,666
Add/(deduct):
Change in unrealized loss (gain) on inventory (1)	5,369			32,326			(20,888)			18,775
Change in unrealized value on natural gas transportation contracts (2)	35,592			(123)			56,711			(13,322)
Gain on sale of fixed assets not in the ordinary course of business including gain on insurance recoveries (7)	(9,725)			—			(9,727)			—
Acquisition related expenses (4)	—			1			—			1
Other adjustments (5)	35			161			65			320
Adjusted EBITDA	$	2,998		$	28,016		$	64,771		$	70,440
Other Data:
Ten Year Average Heating Degree Days (6)	611			574			3,217			3,214
Heating Degree Days (6)	520			774			3,059			2,950
Variance from average heating degree days	(15)		%	35		%	(5)		%	(8)		%
Variance from prior period heating degree days	(33)		%	44		%	4		%	(7)		%

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(1)Inventory is valued at the lower of cost or net realizable value. The adjustment related to change in unrealized gain on inventory which is not included in net income, represents the estimated difference between inventory valued at the lower of cost or net realizable value as compared to market values. The fair value of the derivatives we use to economically hedge our inventory declines or appreciates in value as the value of the underlying inventory appreciates or declines, which creates unrealized hedging losses (gains) with respect to the derivatives that are included in net income.

(2)Represents our estimate of the change in fair value of the natural gas transportation contracts which are not recorded in net income until the transportation is utilized in the future (i.e., when natural gas is delivered to the customer), as these contracts are executory contracts that do not qualify as derivatives. As the fair value of the natural gas transportation contracts decline or appreciate, the offsetting physical or financial derivative will also appreciate or decline creating unmatched unrealized hedging losses (gains) in net income.

(3)For a discussion of the non-GAAP financial measures EBITDA, adjusted EBITDA and adjusted gross margin, see “How Management Evaluates Our Results of Operations.”

(4)We incur expenses in connection with acquisitions and given the nature, variability of amounts, and the fact that these expenses would not have otherwise been incurred as part of our continuing operations, adjusted EBITDA excludes the impact of acquisition related expenses.

(5)Represents the change in the fair value of contingent consideration related to the 2017 Coen Energy acquisition and other expenses.

(6)For purposes of evaluating our results of operations, we use heating degree day amounts as reported by the NOAA Regional Climate Center. In order to incorporate recent average information and to reflect the geographic locations of our customer base, we report degree day information for Boston and New York City (weighted equally) with a historical average for the same geographic locations over the previous ten-year period.

(7)On April 29, 2021, we sold the Oswego terminal to an unaffiliated buyer. In connection with the sale, we recorded a net gain on the sale of $9.0 million for the quarter ended June 30, 2021, which is included within other operating income in the consolidated statements of income. The remaining $0.7 million of other operating income relates to a gain associated with a parcel of land sold at the Bronx terminal.

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Analysis of Operating Segments

Three Months Ended June 30, 2021 compared to Three Months Ended June 30, 2020



	Three Months Ended June 30,				Increase/(Decrease)
	2021		2020		$		%
	(in thousands, except adjusted unit gross margin)
Volumes:
Refined products (gallons)	289,458		264,332		25,126		10	%
Natural gas (MMBtus)	11,692		11,141		551		5	%
Materials handling (short tons)	507		391		116		30	%
Materials handling (gallons)	124,444		148,872		(24,428)		(16)	%
Net Sales:
Refined products	$	589,142	$	292,889	$	296,253	101	%
Natural gas	51,360		47,988		3,372		7	%
Materials handling	12,725		12,974		(249)		(2)	%
Other operations	4,445		4,363		82		2	%
Total net sales	$	657,672	$	358,214	$	299,458	84	%
Adjusted Gross Margin:
Refined products	$	27,165	$	52,861	$	(25,696)	(49)	%
Natural gas	(2,725)		(2,245)		(480)		(21)	%
Materials handling	12,694		12,895		(201)		(2)	%
Other operations	1,696		1,673		23		1	%
Total adjusted gross margin	$	38,830	$	65,184	$	(26,354)	(40)	%
Adjusted Unit Gross Margin:
Refined products	$	0.094	$	0.200	$	(0.106)	(53)	%
Natural gas	$	(0.233)	$	(0.202)	$	(0.031)	(15)	%

Refined Products

Refined products net sales increased $296.3 million, or 101%, compared to the same period last year due primarily to the higher price environment. Average sale prices were up by nearly 84%, with the substantial increase reflecting the price recovery compared to the pandemic-driven price weakness last year. Volumes were also substantially higher at 10% more, also contributing to the higher net sales. The volume gain was mostly a result of higher gasoline sales, driven by the recovery in transportation demand. Distillate volumes were also higher, due principally to an increase in diesel requirements in particular with transit agencies and on-site fueling operations. Heating oil volumes were lower, reflecting the significantly milder temperatures as indicated by the reduction in heating degree days by nearly a third. Heavy oil also contributed to the increased volumes due to gains at our Canadian operations.

Refined products adjusted gross margin decreased $25.7 million, or 49%, compared to the same period last year. This decline was driven primarily by less favorable market conditions to purchase, store, and hedge inventory compared to the unusually strong market environment during the same period last year. Lower unit margins were also a contributor to the margin decrease. Results in our Canadian operations were consistent with the overall trend, again with the key factor the weaker market conditions to purchase, store, and hedge inventory.

Natural Gas

Natural gas net sales increased $3.4 million, or 7%, compared to the same period last year due to a combination of a 5% increase in volumes and a 2% higher average sales price. The higher volumes primarily reflect the improved economic conditions compared to the pandemic environment last year.

Natural gas adjusted gross margin decreased $0.5 million, or 21%, compared to the same period last year, due primarily to a reduction in the adjusted unit gross margins. Factors contributing to the lower adjusted unit gross margins were the warmer temperatures and lower price volatility leading to fewer supply and inventory optimization opportunities as well as basis changes contributing to a reduction in the mark-to-market valuation of market positions.

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Materials Handling

Materials handling net sales and adjusted gross margin were $0.2 million, or 2% lower than the same period last year. Margins were higher in the U.S. operations, with gains led by gypsum, furnace slag and pulp handling more than offsetting reduced liquid bulk activity, in particular the decreases in asphalt and china clay. Results in the Canadian operations were lower due to a reduction in tank rental requirements.

Other Operations

Net sales from other operations increased $0.1 million, or 2%, driven by higher coal volumes compared to the same period last year. Adjusted gross margin was 1% higher than last year, with increased boiler service and coal margins more than offsetting a decline at our Canadian trucking operations.

Six Months Ended June 30, 2021 compared to Six Months Ended June 30, 2020



	Six Months Ended June 30,				Increase/(Decrease)
	2021		2020		$		%
	(in thousands, except adjusted unit gross margin)
Volumes:
Refined products (gallons)	805,303		744,813		60,490		8	%
Natural gas (MMBtus)	30,527		29,469		1,058		4	%
Materials handling (short tons)	924		1,277		(353)		(28)	%
Materials handling (gallons)	182,303		227,319		(45,016)		(20)	%
Net Sales:
Refined products	$	1,505,342	$	1,134,831	$	370,511	33	%
Natural gas	153,935		143,766		10,169		7	%
Materials handling	24,771		28,531		(3,760)		(13)	%
Other operations	9,757		10,965		(1,208)		(11)	%
Total net sales	$	1,693,805	$	1,318,093	$	375,712	29	%
Adjusted Gross Margin:
Refined products	$	78,198	$	88,650	$	(10,452)	(12)	%
Natural gas	38,364		27,542		10,822		39	%
Materials handling	24,770		28,476		(3,706)		(13)	%
Other operations	3,709		3,626		83		2	%
Total adjusted gross margin	$	145,041	$	148,294	$	(3,253)	(2)	%
Adjusted Unit Gross Margin:
Refined products	$	0.097	$	0.119	$	(0.022)	(18)	%
Natural gas	$	1.257	$	0.935	$	0.322	34	%

Refined Products

Refined products net sales increased $370.5 million, or 33%, due primarily to the substantially higher oil price environment compared to the same period last year. In addition, the 8% increase in volumes was a contributor to the higher net sales. The higher volumes were primarily due to distillates, including heating oil and diesel. The increase in heating oil volumes was partly a result of the colder weather, as illustrated by the 4% higher heating degree days. Diesel volumes were up, with gains from regional transit authorities, on-site fueling operations, and marine fueling requirements. Gasoline and heavy oil volumes were also higher. The gain in gasoline volumes was due to a recovery in transportation demand, with the higher heavy oil volumes a result of additional demand at our Canadian operations for on-land requirements.

Refined products adjusted gross margin decreased $10.5 million, or 12%, compared to the same period last year as reduced gross adjusted unit margins more than offset the higher volumes. The lower unit margins were primarily a result of substantially less attractive market conditions to purchase, store and hedge oil inventory compared to the market that was in place last year in conjunction with a surplus supply and weakened demand environment. The Canadian operations was the largest contributor to the weaker results, again due to the less attractive market conditions to purchase, store and hedge oil inventory compared to the same period last year.

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Natural Gas

Natural gas net sales increased $10.2 million, or 7%, compared to the same period last year, due to a 4% increase in volumes and a 3% higher average sales price. A key factor contributing to the higher volumes was an overall improvement in economic conditions compared to the pandemic-driven slowdown last year.

Natural gas adjusted gross margin increased by $10.8 million, or 39%, compared to the same period last year, largely resulting from higher adjusted unit gross margins. The increase in adjusted unit gross margins was primarily due to enhanced supply and inventory optimization opportunities in the early part of the year, in conjunction with colder temperatures and concomitant higher price volatility.

Materials Handling

Materials handling net sales and adjusted gross margin decreased $3.8 million and $3.7 million, respectively, or by 13% each, compared to the same period last year. This decline was a result of comparable reductions in our U.S. and Canadian operations. The decrease in the U.S. was largely due to reduced road salt handling requirements and lower windmill component handling activity. The reduction in salt was a result of fewer bulk vessel deliveries, as a mild winter resulted in lower salt usage and less resupply requirements. Reduced windmill handling revenue resulted since there were lower component deliveries compared to the substantial activity early last year. The reduction in the Canadian operations was a result of reduced tank rental demand from third parties.

Other Operations

Net sales from other operations decreased by $1.2 million, or 11%, due primarily to reduced coal volumes compared to the same period last year. Adjusted gross margin was $0.1 million, or 2% higher than last year, due to a combination of an increase in boiler service activity and higher coal adjusted gross unit margins.

Operating Costs and Expenses

Three Months Ended June 30, 2021 compared to Three Months Ended June 30, 2020


	Three Months Ended June 30,				Increase/(Decrease)
	2021		2020		$		%
	(in thousands)
Operating expenses	$	19,148	$	18,471	$	677	4%
Selling, general and administrative	$	16,719	$	18,923	$	(2,204)	(12)%
Depreciation and amortization	$	8,258	$	8,518	$	(260)	(3)%
Interest expense, net	$	8,510	$	10,716	$	(2,206)	(21)%

Operating Expenses. Operating expenses increased $0.7 million, or 4%, compared to the same period last year, primarily reflecting an increase of $0.4 million of employee overtime and $0.4 million of stockpile and boiler fuel expenses.

Selling, General and Administrative Expenses. SG&A expenses decreased $2.2 million, or 12%, compared to the same period last year largely driven by a decrease of $1.9 million in incentive compensation expense and a $0.5 million decrease in audit and legal costs.

Depreciation and Amortization. Depreciation and amortization was approximately flat as increased depreciation expense offset decreased amortization expense.

Interest Expense, net. Interest expense, net decreased $2.2 million, or 21%, compared to the same period last year primarily due to decreased net borrowing rates.

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Six Months Ended June 30, 2021 compared to Six Months Ended June 30, 2020




	Six Months Ended June 30,				Increase/(Decrease)
	2021		2020		$		%
	(in thousands)
Operating expenses	$	38,379	$	39,283	$	(904)	(2)%
Selling, general and administrative	$	41,958	$	38,956	$	3,002	8%
Depreciation and amortization	$	16,741	$	17,115	$	(374)	(2)%
Interest expense, net	$	17,259	$	21,826	$	(4,567)	(21)%

Operating Expenses. Operating expenses decreased $0.9 million, or 2%, compared to the same period last year, reflecting $1.0 million of decreased stockpile and boiler fuel expenses offset by an increase of $0.4 million for employee-related costs.

Selling, General and Administrative Expenses. SG&A expenses increased $3.0 million or 8%, compared to the same period last year. This increase was driven by $3.4 million in higher incentive compensation and $0.7 million increase in employee-related costs partially offset by decrease to audit and legal costs of $0.9 million.

Depreciation and Amortization. Depreciation and amortization increased $0.4 million or 2% as increased depreciation expense was partially offset by decreased amortization expense.

Interest Expense, net. Interest expense, net decreased $4.6 million, or 21%, compared to the same period last year primarily due to decreased net borrowing rates.

Liquidity and Capital Resources

Liquidity

Our primary liquidity needs are to fund our working capital requirements, operating expenses, capital expenditures and quarterly distributions. Cash generated from operations, our borrowing capacity under our Credit Agreement (as defined below) and potential future issuances of additional partnership interests or debt securities are our primary sources of liquidity. At June 30, 2021, we had a working capital deficit of $30.5 million.

As of June 30, 2021, the undrawn borrowing capacity under the working capital facilities of our Credit Agreement was $121.8 million and the undrawn borrowing capacity under the acquisition facility was $58.7 million. We enter our seasonal peak period during the fourth quarter of each year, during which inventory, accounts receivable and debt levels increase. As we move out of the winter season at the end of the first quarter of the following year, typically inventory is reduced, accounts receivable are collected and converted into cash and debt is paid down. During the six months ended June 30, 2021, the amount drawn under the working capital facilities of our Credit Agreement fluctuated from a low of $200.3 million to a high of $402 million.

We believe that we have sufficient liquid assets, cash flow from operations and borrowing capacity under our Credit Agreement 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 flow would likely have an adverse effect on our ability to meet our financial commitments and debt service obligations.

Credit Agreement

On May 11, 2021, Sprague Operating Resources LLC (the “U.S. Borrower”) and Kildair Service ULC (the “Canadian Borrower” and, together with the U.S. Borrower, the “Borrowers”), wholly owned subsidiaries of the Partnership, entered into a first amendment (the “First Amendment”) to the second amended and restated credit agreement dated as of May 19, 2020 (the "Original Credit Agreement" the Original Credit Agreement as amended by the First Amendment, the “Credit Agreement"). Upon the effective date, the First Amendment increased the acquisition facility from $430 million to $450 million was accounted for as a modification of a syndicated loan arrangement with partial extinguishment to the extent there was a decrease in the borrowing capacity on a creditor by creditor basis. The Credit Agreement matures on May 19, 2023. The Partnership and certain of its subsidiaries (the “Subsidiary Guarantors”) are guarantors of the obligations under the Credit Agreement. Obligations under the Credit Agreement are secured by substantially all of the assets of the Partnership, the Borrowers and the Subsidiary Guarantors (collectively, the “Loan Parties”).

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As of June 30, 2021, the revolving credit facilities under the Credit Agreement contained, among other items, the following:

•A committed U.S. dollar revolving working capital facility of up to $465.0 million, subject to borrowing base limits, to be used for working capital loans and letters of credit;

•A multicurrency revolving working capital facility of up to $85.0 million, subject to borrowing base limits, to be used for working capital loans and letters of credit;

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The Credit Agreement contains various covenants and restrictive provisions that, among other things, prohibit the Partnership from making distributions to unitholders if any event of default occurs or would result from the distribution or if the Loan Parties would not be in pro forma compliance with the financial covenants after giving effect to the distribution. In addition, the Credit Agreement contains various covenants that are usual and customary for a financing of this type, size and purpose, including, but not limited to, covenants that require the Loan Parties to maintain: a minimum consolidated EBITDA-to-fixed charge ratio, a minimum consolidated net working capital amount and a maximum consolidated total leverage-to-EBITDA ratio. The Credit Agreement also limits the Loan Parties ability to incur debt, grant liens, make certain investments or acquisitions, enter into affiliate transactions and dispose of assets. The Partnership was in compliance with the covenants under the Credit Agreement at June 30, 2021.

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements.

Capital Expenditures

Our terminals require investments to maintain, expand, upgrade or enhance existing assets and to comply with environmental and operational regulations. Our capital requirements primarily consist of maintenance capital expenditures and expansion capital expenditures. We define maintenance capital expenditures as capital expenditures made to replace assets, or to maintain the long-term operating capacity of our assets or operating income. Examples of maintenance capital expenditures are expenditures required to maintain equipment reliability, terminal integrity and safety and to address environmental laws and regulations. Costs for repairs and minor renewals to maintain facilities in operating condition and that do not extend the useful life of existing assets will be treated as maintenance expenses as we incur them. We define expansion capital expenditures as capital expenditures made to increase the long-term operating capacity of our assets or our operating income whether through construction or acquisition of additional assets. Examples of expansion capital expenditures include the acquisition of equipment and the development or acquisition of additional storage capacity, to the extent such capital expenditures are expected to expand our operating capacity or our operating income.

The following table summarizes expansion and maintenance capital expenditures for the periods indicated. This information excludes property, plant and equipment acquired in business combinations:


	Capital Expenditures
	Expansion		Maintenance		Total
	(in thousands)
Six Months Ended June 30,
2021	$	1,691	$	4,108	$	5,799
2020	$	2,287	$	3,099	$	5,386

We anticipate that future maintenance capital expenditures will be funded with cash generated by operations and that future expansion capital requirements will be provided through long-term borrowings or other debt financings and/or equity offerings.

Cash Flows


	Six Months Ended June 30,
	2021		2020
	(in thousands)
Net cash provided by operating activities	$	159,152	$	177,281
Net cash provided by (used in) investing activities	$	5,326	$	(5,145)
Net cash used in financing activities	$	(161,495)	$	(172,945)

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Operating Activities

Net cash provided by operating activities for the six months ended June 30, 2021 was $159.2 million. Cash inflows for the period were the result of a decrease of $52.9 million in inventories largely due to a reduction in seasonal inventory requirements, net income of $3.2 million, a decrease of $54.3 million in other assets driven by changes in collateral, decrease of $34.7 million in accounts receivable and $29.9 million representing the net impact in our derivative instruments as a result of contract activity and changes in commodity prices during the period. These inflows were offset by cash outflows as a result of a reduction of $19.1 million in accounts payable and accrued liabilities primarily relating to the timing of invoice payments for product purchase.

Net cash provided by operating activities for the six months ended June 30, 2020 was $177.3 million. Cash inflows for the period were the result of a decrease of $96.8 million in inventories due to a reduction in seasonal inventory requirements, a decrease of $173.8 million in accounts receivable due to a seasonal reduction in sales volume and net income of $21.6 million. These inflows were offset by cash outflows as a result of a reduction of $113.3 million in accounts payable and accrued liabilities primarily relating to the timing of invoice payments for product purchases and $29.7 million representing the net impact in our derivative instruments as a result of contract activity and changes in commodity prices during the period.

Investing Activities

Net cash provided by investing activities for the six months ended June 30, 2021 was $5.3 million, and primarily resulted from the sale of Oswego terminal generating $11.1 million in proceeds partially offset by $1.7 million related to expansion capital expenditures and $4.1 million related to maintenance capital expenditure projects across our terminal system.

Net cash used in investing activities for the six months ended June 30, 2020 was $5.1 million, and primarily resulted from $2.3 million related to expansion capital expenditures and $3.1 million related to maintenance capital expenditure projects across our terminal system.

Financing Activities

Net cash used in financing activities for the six months ended June 30, 2021 was $161.5 million, and primarily resulted from $117.4 million of payments under our Credit Agreement due to reduced financing requirements from accounts receivable levels, the reduction of inventory levels and distributions of $34.9 million.

Net cash used in financing activities for the six months ended June 30, 2020 was $172.9 million, and primarily resulted from $131.6 million of payments under our Credit Agreement due to reduced financing requirements from accounts receivable levels, the reduction of inventory levels and distributions of $32.6 million.

Impact of Inflation

Inflation in the United States and Canada has been relatively low in recent years and did not have a material impact on our results of operations for the six months ended June 30, 2021 and 2020.

Critical Accounting Policies and Estimates

Part I, Item, 2, "Management’s Discussion and Analysis of Financial Condition and Results of Operations” discusses our Condensed Consolidated Financial Statements, which have been prepared in accordance with GAAP. The preparation of these Condensed 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 Condensed Consolidated Financial Statements and the reported amounts of revenues and expenses during the reporting period. Actual results may differ from these estimates under different assumptions or conditions.

These estimates are based on our knowledge and understanding of current conditions and actions that we may take in the future. Changes in these estimates will occur as a result of the passage of time and the occurrence of future events. Subsequent changes in these estimates may have a significant impact on our financial condition and results of operations and are recorded in the period in which they become known. We have identified the following estimates that, in our opinion, are subjective in nature, require the exercise of judgment and involve complex analysis: the fair value of derivative assets and liabilities, goodwill impairment assessment, and revenue recognition and cost of products sold.

The significant accounting policies and estimates that have been adopted and followed in the preparation of our Condensed Consolidated Financial Statements are detailed in Note 1 - Description of Business and Summary of Significant Accounting Policies included in our 2020 Annual Report. There have been no changes in these policies and estimates that had a significant impact on the financial condition and results of operations for the periods covered in this Quarterly Report.

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Recent Accounting Pronouncements

For information on recent accounting pronouncements impacting our business, see "Recent Accounting Pronouncements" included under Note 1 - Description of Business and Summary of Significant Accounting Policies to our Condensed Consolidated Financial Statements.

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Item 3.			Quantitative and Qualitative Disclosures about Market Risk

Market risk is the risk of loss arising from adverse changes in market rates and prices. The principal market risks to which we are exposed are commodity price risk, interest rate risk and market/credit risk. We utilize various derivative instruments to manage exposure to commodity risk and swaps to manage exposure to interest rate risk.

Commodity Price Risk

We use various financial instruments as we seek to hedge our commodity price risk. We sell our refined products and natural gas primarily in the Northeast. We hedge our refined products positions primarily with a combination of futures contracts that trade on the New York Mercantile Exchange, or NYMEX, and fixed-for-floating price swaps in the form of bilateral contracts that are traded “over-the-counter” or "OTC". Although there are some notable differences between futures and the fixed-for-floating price swaps, both can provide a fixed price while the counterparty receives a price that fluctuates as market prices change.

As indicated in the table below, we primarily use futures contracts to hedge light oil transactions and swaps contracts for hedging residual fuel oils. There are no residual fuel oil futures contracts that actively trade in the United States. Each of the financial instruments trade by month for many months forward, allowing us the ability to hedge future contractual commitments.


Product Group						Primary Financial Hedging Instrument
Gasolines						NYMEX RBOB futures contract
Distillates						NYMEX Ultra Low Sulfur Diesel futures contract
Residual Fuel Oils						New York Harbor 1% Sulfur Residual Fuel Oil swaps contract

In addition to the financial instruments listed above, we may periodically use the ethanol futures contract that trades on the Chicago Board of Trade, or CBOT, to hedge ethanol that is used for blending into our gasoline. This ethanol contract is based on Chicago delivery. There are also swaps alternatives available in the market to hedge ethanol. In addition, we also use Rotterdam Barge 0.1% Sulfur Gasoil swaps as the primary means to hedge Kildair's marine gas oil positions.

For natural gas, there are no quality differences that need to be considered when hedging. Our primary hedging requirements relate to fixed price and basis (location) exposure. We largely hedge our natural gas fixed price exposure using fixed-for-floating price swaps that trade on the Intercontinental Exchange ("ICE") with the prices based on the Henry Hub location near Erath, Louisiana. The Henry Hub is the most active natural gas trading location in the United States. Although we typically use swaps, there is also an actively traded NYMEX Henry Hub natural gas futures contract that we can use. We primarily use ICE basis swaps as the key financial instrument type to hedge our natural gas basis risk. Similar to the natural gas futures and ICE Henry Hub swaps, basis swaps for major locations trade actively for many months. These swaps are financially settled, typically using prices quoted by Platts. We also directly hedge our price exposure in oil and natural gas by using forward purchases or sales that require physical delivery of the product.

The following table presents total realized and unrealized gains (losses) on derivative instruments utilized for commodity risk management purposes. Such amounts are included in cost of products sold (exclusive of depreciation and amortization) for the periods presented.


	Three Months Ended June 30,				Six Months Ended June 30,
	(in thousands)
	2021		2020		2021		2020
Refined products contracts	$	(19,503)	$	(8,869)	$	(39,277)	$	57,336
Natural gas contracts	(34,447)		3,332		(33,138)		39,345
Total	$	(53,950)	$	(5,537)	$	(72,415)	$	96,681

Substantially all of our commodity derivative contracts outstanding as of June 30, 2021 will settle prior to December 31, 2022.

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Interest Rate Risk

We enter into interest rate swaps to manage exposures in changing interest rates. We swap the variable LIBOR interest rate payable under our Credit Agreement for fixed LIBOR interest rates. These interest rate swaps meet the criteria to receive cash flow hedge accounting treatment. Counterparties to our interest rate swaps are large multi-national banks and we do not believe there is a material risk of counterparty nonperformance. Additionally, we may enter into seasonal swaps which are intended to manage our increase in borrowings during the winter, as a result of higher inventory and accounts receivable levels.

Our interest rate swap agreements outstanding as of June 30, 2021 were as follows (in thousands):


Beginning	Ending	Notional Amount

January 2021	January 2022	$	300,000


April 2021	April 2022	$	25,000
January 2022	January 2023	$	250,000
April 2022	April 2023	$	25,000
January 2023	January 2024	$	250,000
January 2024	January 2025	$	50,000

During the two year period ended June 30, 2021 we hedged approximately 48% of our floating rate debt with fixed-for-floating interest rate swaps. We expect to continue to utilize interest rate swaps to manage our exposure to LIBOR interest rates. Based on a sensitivity analysis for the twelve months ended June 30, 2021, we estimate that if short-term interest rates increase 100 basis points or decrease to zero, our interest expense would have increased approximately $3.5 million and decreased approximately $0.4 million, respectively. These amounts were estimated by considering the effect of the hypothetical short-term interest rates on variable-rate debt outstanding, adjusted for interest rate hedges.

Derivative Instruments

The following tables present our derivative assets and derivative liabilities measured at fair value on a recurring basis as of June 30, 2021:


	As of June 30, 2021
	Fair Value Measurement		Active Markets Level 1		Observable Inputs Level 2		Unobservable Inputs Level 3
	(in thousands)
Derivative assets:

Commodity fixed forwards	$	24,024	$	—	$	24,024	$	—
Futures, swaps and options	113,175		113,175		—		—
Commodity derivatives	137,199		113,175		24,024		—


Total derivative assets	$	137,199	$	113,175	$	24,024	$	—
Derivative liabilities:

Commodity fixed forwards	86,925		—		86,925		—
Futures, swaps and options	74,015		73,923		92		—
Commodity derivatives	160,940		73,923		87,017		—
Interest rate swaps	10,146		—		10,146		—

Total derivative liabilities	$	171,086	$	73,923	$	97,163	$	—

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Market and Credit Risk

The risk management activities for our refined products and natural gas segments involve managing exposures to the impact of market fluctuations in the price and transportation costs for commodities through the use of derivative instruments. The prices for energy commodities can be significantly influenced by market liquidity and changes in seasonal demand, weather conditions, transportation availability, and federal and state regulations. We monitor and manage our exposure to market risk on a daily basis in accordance with approved policies.

We maintain a control environment under the direction of our Chief Risk Officer through our risk management policy, processes and procedures, which our senior management has approved. Control measures include volumetric, value at risk, and stop loss limits, as well as contract term limits. Our Chief Risk Officer and Risk Management Committee must approve the use of new instruments or new commodities. Risk limits are monitored and reported daily to senior management. Our risk management department also performs independent verifications of sources of fair values. These controls apply to all of our commodity risk management activities.

We use a value at risk model to monitor commodity price risk within our risk management activities. The value at risk model uses both linear and simulation methodologies based on historical information, with the results representing the potential loss in fair value over one day at a 95% confidence level. Results may vary from time to time as hedging coverage, market pricing levels and volatility change.

We have a number of financial instruments that are potentially at risk including cash and cash equivalents, receivables and derivative contracts. Our primary exposure is credit risk related to our receivables and counterparty performance risk related to the fair value of derivative assets, which is the loss that may result from a customer’s or counterparty’s non-performance. We use credit policies to control credit risk, including utilizing an established credit approval process, monitoring customer and counterparty limits, employing credit mitigation measures such as analyzing customer financial statements, credit insurance with a third party provider and accepting personal guarantees and forms of collateral. We believe that our counterparties will be able to satisfy their contractual obligations. Credit risk is limited by the large number of customers and counterparties comprising our business and their dispersion across different industries.

Cash is held in demand deposit and other short-term investment accounts placed with federally insured financial institutions. Such deposit accounts at times may exceed federally insured limits. We have not experienced any losses on such accounts.

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Item 4.			Controls and Procedures

Disclosure Controls and Procedures

Disclosure controls and procedures are designed to ensure that information required to be disclosed in the Partnership's reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed in the Partnership's reports under the Exchange Act is accumulated and communicated to the Partnership's management, including the President and Chief Executive Officer and the Chief Financial Officer of our General Partner, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

As of June 30, 2021, the Partnership carried out an evaluation, under the supervision and with the participation of management (including the President and Chief Executive Officer and Chief Financial Officer of the General Partner) of the effectiveness of the design and operation of the Partnership's disclosure controls and procedures pursuant to Exchange Act Rule 13a-15. Based on this evaluation, the General Partner's President and Chief Executive Officer and Chief Financial Officer concluded that the Partnership's disclosure controls and procedures were effective as of June 30, 2021.

Changes in Internal Control Over Financial Reporting

There have been no changes in our system of internal control over financial reporting during the three months ended June 30, 2021 that have materially affected, or are reasonably likely to materially affect, the Partnership’s internal control over financial reporting.

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PART II—OTHER INFORMATION


Item 1.			Legal Proceedings

From time to time, we are a party to various legal proceedings or claims arising in the ordinary course of business. For information related to legal proceedings, see the discussion under the caption Legal, Environmental and Other Proceedings in Note 10 - Commitments and Contingencies to our consolidated financial statements included in Part I, Item 1 of this Quarterly Report, which information is incorporated by reference into this Part II, Item 1.


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” included in our 2020 Annual Report, which could materially affect our business, financial condition or future results.


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

None.


Item 3.			Defaults Upon Senior Securities

None.


Item 4.			Mine Safety Disclosures

Not applicable.


Item 5.			Other Information

None.

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Item 6. Exhibits

The exhibits listed in the accompanying Exhibits Index are filed or incorporated by reference as part of this Form 10-Q.

EXHIBIT INDEX


Exhibit No.						Description
2.1***						Purchase and Sale Agreement, dated September 18, 2017, by and among Sprague Operating Resources LLC, Coen Oil Company, LLC, Coen Markets, Inc., and The Thomaston Land Company, LLC (incorporated by reference to Exhibit 2.1 of Sprague Resources LP's Current Report on Form 8-K filed September 19, 2017 (File No. 001-36137)).

3.1						Certificate of Limited Partnership of Sprague Energy Partners LP (incorporated by reference to Exhibit 3.1 of Sprague Resources LP’s Registration Statement on Form S-1 filed July 27, 2011 (File No. 333-175826)).

3.2						Amendment to the Certificate of Limited Partnership of Sprague Energy Partners LP (Changing Name to Sprague Resources LP) (incorporated by reference to Exhibit 3.2 of Sprague Resources LP’s Registration Statement on Form S-1 filed July 27, 2011 (File No. 333-175826)).

3.3						Amendment No. 3 to the First Amended and Restated Agreement of Limited Partnership of Sprague Resources LP dated as of October 30, 2013, effective March 1, 2021 (incorporated by reference to Exhibit 3.3 of Sprague Resources LP’s Annual Report on Form 10-K filed March 4, 2021 (File No. 001-36137)).

3.4						Amendment No. 2 to the First Amended and Restated Agreement of Limited Partnership of Sprague Resources LP dated as of October 30, 2013 effective October 25, 2019 (incorporated by reference to Exhibit 3.1 of Sprague Resources LP's Current Report on Form 8-K filed October 25, 2019 (File No. 001-36137)).

3.5						Amendment No. 1 to the First Amended and Restated Agreement of Limited Partnership of Sprague Resources LP dated as of October 30, 2013 effective December 20, 2017 (incorporated by reference to Exhibit 3.1 of Sprague Resources LP's Current Report on Form 8-K filed December 20, 2017 (File No. 001-36137)).

3.6						First Amended and Restated Agreement of Limited Partnership of Sprague Resources LP (incorporated by reference to Exhibit 3.1 of Sprague Resources LP’s Current Report on Form 8-K filed November 5, 2013 (File No. 001-36137)).

3.7						Second Amended and Restated Limited Liability Company Agreement of Sprague Resources GP LLC (incorporated by reference to Exhibit 3.1 of Sprague Resources LP’s Current Report on Form 8-K filed May 28, 2021 (File No. 001-36137)).

3.8						Composite copy of the First Amended and Restated Agreement of Limited Partnership of Sprague Resources LP, dated as of October 30, 2013, as amended by Amendment No. 1, effective December 20, 2017, Amendment No. 2, effective October 25, 2019, and Amendment No. 3, effective March 1, 2021 (incorporated by reference to Exhibit 3.8 of Sprague Resources LP’s Annual Report on Form 10-K filed March 4, 2021 (File No. 001-36137)).

10.1						Offer Letter with Ben Hennelly, dated April 19, 2021 (incorporated by reference to Exhibit 10.1 of Sprague Resources LP’s Current Report on Form 8-K filed April 21, 2021 (File No. 001-36137)).

10.2						First Amendment, dated May 11, 2021, to Second Amended and Restated Credit Agreement, dated May 19, 2020, among Sprague Operating Resources LLC, as U.S. borrower, Kildair Service ULC, as Canadian borrower, the several lenders parties thereto, MUFG Bank Ltd., as administrative agent, the co-syndication agents, the co-collateral agents and the co-documentation agents party thereto (incorporated by reference to Exhibit 10.1 of Sprague Resources LP’s Current Report on Form 8-K filed May 11, 2021 (File No. 001-36137)).

31.1*						Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, Rule 13a-14(a) /15d-14(a), by Chief Executive Officer.

31.2*						Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, Rule 13a-14(a) /15d-14(a), by Chief Financial Officer.

32.1**						Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, by Chief Executive Officer.

32.2**						Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, by Chief Financial Officer.

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101.INS*						Inline XBRL Instance Document - The instance document does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document.

101.SCH*						Inline XBRL Taxonomy Extension Schema Document

101.CAL*						Inline XBRL Taxonomy Extension Calculation

101.DEF*						Inline XBRL Taxonomy Extension Definition

101.LAB*						Inline XBRL Taxonomy Extension Label Linkbase

101.PRE*						Inline XBRL Taxonomy Extension Presentation

104*						Cover Page Interactive Data File (Formatted as Inline XBRL and contained in Exhibit 101)

*						Filed herewith.
**						Furnished herewith in accordance with Item 601(b)(32) of Regulation S-K.
***						Pursuant to Item 601(b)(2) of Regulation S-K, certain schedules to the Asset Purchase Agreements have been omitted. The registrant hereby agrees to furnish supplementally to the SEC, upon its request, any or all omitted schedules.

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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.


	SPRAGUE RESOURCES LP

	By:	Sprague Resources GP LLC,
		Its General Partner

Date: August 5, 2021		/s/ David C. Long
		David C. Long Chief Financial Officer (on behalf of the registrant, and in his capacity as Principal Financial Officer)