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 ~~March 31,~~June 30, 2020



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 Hampshire03801

(Address of principal executive offices)

Registrant’s telephone number, including area code: ~~(800)~~ (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
Common Units Representing Limited Partner Interests

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 22,922,902 common units outstanding as of ~~May 7,~~August 6, 2020.

Table of Contents



		Page
PART I—FINANCIAL INFORMATION

Item 1.	Financial Statements:
	Condensed Consolidated Balance Sheets as of ~~March 31,~~June 30, 2020 (unaudited) and December 31, 2019	1
	Unaudited Condensed Consolidated Income Statements for the three and six months ended ~~March 31,~~June 30, 2020 and ~~March 31,~~June 30, 2019	2
	Unaudited Condensed Consolidated Statements of Comprehensive (Loss) Income for the three and six months ended ~~March 31,~~June 30, 2020 and ~~March 31,~~June 30, 2019	3
	Unaudited Condensed Consolidated Statements of Unitholders’ Equity for the three and six months ended ~~March 31,~~June 30, 2020 and ~~March 31,~~June 30, 2019	4
	Unaudited Condensed Consolidated Statements of Cash Flows for the ~~three~~six months ended ~~March 31,~~June 30, 2020 and ~~March 31,~~June 30, 2019	5
	Notes to Unaudited Condensed Consolidated Financial Statements	6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	2021
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	3338
Item 4.	Controls and Procedures	3641

PART II—OTHER INFORMATION

Item 1.	Legal Proceedings	3742
Item 1A.	Risk Factors	3742
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	3742
Item 3.	Defaults Upon Senior Securities	3742
Item 4.	Mine Safety Disclosures	3742
Item 5.	Other Information	3742
Item 6.	Exhibits	3843
Signatures		4045

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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)


	March 31, 2020			December 31, 2019			June 30, 2020			December 31, 2019
	(Unaudited)						(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	9,555		$	5,386		$	3,748		$	5,386
Accounts receivable, net	181,232			281,527			107,158			281,527
Inventories	109,926			293,224			196,439			293,224
Fair value of derivative assets	334,654			77,871			191,330			77,871
Other current assets	31,517			63,705			58,800			63,705
Total current assets	666,884			721,713			557,475			721,713
Fair value of derivative assets, long-term	44,313			16,807			30,400			16,807
Property, plant and equipment, net	344,715			348,039			340,961			348,039
Intangibles, net	47,491			49,764			45,296			49,764
Other assets, net	21,211			24,183			24,254			24,183
Goodwill	115,037			115,037			115,037			115,037
Total assets	$	1,239,651		$	1,275,543		$	1,113,423		$	1,275,543
Liabilities and unitholders’ equity
Current liabilities:
Accounts payable	$	76,876		$	147,577		$	38,771		$	147,577
Accrued liabilities	61,027			43,386			39,817			43,386
Fair value of derivative liabilities	243,367			74,154			172,233			74,154
Due to General Partner	5,054			5,653			4,373			5,653
Current portion of working capital facilities	282,900			437,184			288,054			437,184
Current portion of other obligations	14,028			13,858			14,286			13,858
Total current liabilities	683,252			721,812			557,534			721,812
Commitments and contingencies
Acquisition facility	352,000			374,600			392,000			374,600
Fair value of derivative liabilities, long-term	18,230			13,439			20,488			13,439
Other obligations, less current portion	40,191			41,413			39,233			41,413
Operating lease liabilities, less current portion	9,614			11,850			9,181			11,850
Due to General Partner	2,523			2,445			2,601			2,445
Deferred income taxes	15,656			16,202			15,538			16,202
Total liabilities	1,121,466			1,181,761			1,036,575			1,181,761
Unitholders’ equity:
Common unitholders - public (10,695,404 and 10,641,561 units issued and outstanding as of March 31, 2020 and December 31, 2019, respectively)	194,513			180,302
Common unitholders - affiliated (12,227,498 and 12,106,348 units issued and outstanding as of March 31, 2020 and December 31, 2019, respectively)	(48,474		)	(66,832		)
Common unitholders - public (9,971,666 and 10,641,561 units issued and outstanding as of June 30, 2020 and December 31, 2019, respectively)							163,075			180,302
Common unitholders - affiliated (12,951,236 and 12,106,348 units issued and outstanding as of June 30, 2020 and December 31, 2019, respectively)							(58,679		)	(66,832		)
Accumulated other comprehensive loss, net of tax	(27,854		)	(19,688		)	(27,548		)	(19,688		)
Total unitholders’ equity	118,185			93,782			76,848			93,782
Total liabilities and unitholders’ equity	$	1,239,651		$	1,275,543		$	1,113,423		$	1,275,543

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 March 31,						Three Months Ended June 30,						Six Months Ended June 30,
	2020			2019			2020			2019			2020			2019
Net sales	$	959,879		$	1,258,308		$	358,214		$	662,018		$	1,318,093		$	1,920,326
Cost of products sold (exclusive of depreciation and amortization)	850,020			1,159,112			325,233			608,660			1,175,252			1,767,772
Operating expenses	20,812			23,789			18,471			21,075			39,283			44,864
Selling, general and administrative	20,033			20,913			18,923			17,827			38,956			38,739
Depreciation and amortization	8,598			8,388			8,518			8,408			17,115			16,797
Total operating costs and expenses	899,463			1,212,202			371,145			655,970			1,270,606			1,868,172
Operating income	60,416			46,106
Operating (loss) income							(12,931		)	6,048			47,487			52,154
Other income							64			128			64			128
Interest income	175			187			72			140			248			326
Interest expense	(11,286		)	(11,959		)	(10,788		)	(10,038		)	(22,074		)	(21,997		)
Income before income taxes	49,305			34,334
(Loss) income before income taxes							(23,583		)	(3,722		)	25,725			30,611
Income tax provision	(2,571		)	(413		)	(1,542		)	(1,056		)	(4,113		)	(1,469		)
Net income	46,734			33,921
Net (loss) income							(25,125		)	(4,778		)	21,612			29,142
Incentive distributions declared	(2,072		)	(2,055		)	(2,072		)	(2,055		)	(4,144		)	(4,110		)
Limited partners' interest in net income	$	44,662		$	31,866
Limited partners' interest in net (loss) income							$	(27,197	)	$	(6,833	)	$	17,468		$	25,032

Net income per limited partner unit:
Net (loss) income per limited partner unit:
Common - basic	$	1.96		$	1.40		$	(1.19	)	$	(0.30	)	$	0.76		$	1.10
Common - diluted	$	1.95		$	1.40		$	(1.19	)	$	(0.30	)	$	0.76		$	1.10
Units used to compute net income per limited partner unit:	Units used to compute net income per limited partner unit:						Units used to compute net income per limited partner unit:
Common - basic	22,820,983			22,733,977			22,922,902			22,733,977			22,871,943			22,733,977
Common - diluted	22,871,748			22,739,609			22,922,902			22,733,977			22,937,273			22,754,556
Distribution declared per unit	$	0.6675		$	0.6675		$	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 March 31,
2020 2019
Net income $ 46,734
$ 33,921
Other comprehensive loss, net of tax:
Unrealized loss on interest rate swaps
Net loss arising in the period (8,529 ) (2,944 )
Reclassification adjustment related to loss (gain) realized in income 615
(202 )
Net change in unrealized loss on interest rate swaps (7,914 ) (3,146 )
Tax effect 62
25
(7,852 ) (3,121 )
Foreign currency translation adjustment (314 ) 61
Other comprehensive loss (8,166 ) (3,060 )
Comprehensive income $ 38,568
$ 30,861



	Three Months Ended June 30,						Six Months Ended June 30,
	2020			2019			2020			2019
Net (loss) income	$	(25,125	)	$	(4,778	)	$	21,612		$	29,142
Other comprehensive income (loss), net of tax:
Unrealized gain (loss) on interest rate swaps
Net loss arising in the period	(1,257		)	(5,000		)	(9,785		)	(7,944		)
Reclassification adjustment related to loss (gain) realized in income	1,441			(185		)	2,056			(387		)
Net change in unrealized gain (loss) on interest rate swaps	184			(5,185		)	(7,729		)	(8,331		)
Tax effect	(1		)	40			60			65
	183			(5,145		)	(7,669		)	(8,266		)
Foreign currency translation adjustment	123			71			(191		)	132
Other comprehensive income (loss)	306			(5,074		)	(7,860		)	(8,134		)
Comprehensive (loss) income	$	(24,819	)	$	(9,852	)	$	13,752		$	21,008

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-
Sprague
Holdings Incentive Distribution Rights Accumulated
Other
Comprehensive
Loss Total

Balance at December 31, 2018 $ 196,680
$ (48,182 ) $ —
$ (11,522 ) $ 136,976
Net income 14,897
16,969
2,055
—
33,921
Other comprehensive loss —
—
—
(3,060 ) (3,060 )
Unit-based compensation (92 ) (105 ) —
—
(197 )
Distributions paid in cash (7,094 ) (8,081 ) (2,055 ) —
(17,230 )
Balance at March 31, 2019 $ 204,391

$ (39,399 )
$ —

$ (14,582 )
$ 150,410

Balance at December 31, 2019 $ 180,302
$ (66,832 ) $ —
$ (19,688 ) $ 93,782
Net income 20,839
23,823
2,072
—
46,734
Other comprehensive loss —
—
—
(8,166 ) (8,166 )
Unit-based compensation 191
218
—
—
409
Distributions paid in cash (7,103 ) (8,081 ) —
—
(15,184 )
Distribution paid in units —
2,072
(2,072 ) —
—
Common units issued in connection with annual bonus

423
484
—
—
907
Units withheld for employee tax obligations (139 ) (158 ) —
—
(297 )
Balance at March 31, 2020 $ 194,513

$ (48,474 )
$ —

$ (27,854 ) $ 118,185



	Common- Public			Common- Sprague Holdings			Incentive Distribution Rights			Accumulated Other Comprehensive Loss			Total

Three Months Ended June 30, 2019 and 2020
Balance at March 31, 2019	$	204,391		$	(39,399	)	$	—		$	(14,582	)	$	150,410
Net loss	(3,194		)	(3,639		)	2,055			—			(4,778		)
Other comprehensive loss	—			—			—			(5,074		)	(5,074		)
Unit-based compensation	64			75			—			—			139
Distributions paid in cash	(7,094		)	(8,081		)	(2,055		)	—			(17,230		)
Balance at June 30, 2019	$	194,167		$	(51,044	)	$	—		$	(19,656	)	$	123,467

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		)
Distribution 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

Six Months Ended June 30, 2019 and 2020
Balance at December 31, 2018	$	196,680		$	(48,182	)	$	—		$	(11,522	)	$	136,976
Net income	11,702			13,330			4,110			—			29,142
Other comprehensive loss	—			—			—			(8,134		)	(8,134		)
Unit-based compensation	(27		)	(30		)	—			—			(57		)
Distributions paid in cash	(14,188		)	(16,162		)	(4,110		)	—			(34,460		)
Balance at June 30, 2019	$	194,167		$	(51,044	)	$	—		$	(19,656	)	$	123,467

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		)
Distribution 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

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)


	Three Months Ended March 31,						Six Months Ended June 30,
	2020			2019			2020			2019
Cash flows from operating activities
Net income	$	46,734		$	33,921		$	21,612		$	29,142
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation and amortization (includes amortization of deferred debt issuance costs)	9,495			9,286			20,040			18,592
Loss on sale of assets	(4		)	(5		)
Gain (loss) on sale of assets							27			(142		)
Changes in fair value of contingent consideration	121			147			244			297
Provision for doubtful accounts	(33		)	78			539			501
Non-cash unit-based compensation	409			(197		)	1,261			(57		)
Other	38			24			—			48
Deferred income taxes	(484		)	1,024			(603		)	350
Changes in assets and liabilities:
Accounts receivable	100,328			(4,947		)	173,829			108,544
Inventories	183,298			49,751			96,785			133,003
Other assets	34,264			(14,868		)	7,576			(14,033		)
Fair value of commodity derivative instruments	(118,199		)	32,777			(29,654		)	24,682
Due to General Partner and affiliates	(522		)	(429		)	(1,125		)	(2,268		)
Accounts payable, accrued liabilities and other	(54,344		)	(109,537		)	(113,250		)	(161,189		)
Net cash provided by (used in) operating activities	201,101			(2,975		)
Net cash provided by operating activities							177,281			137,470
Cash flows from investing activities
Purchases of property, plant and equipment	(3,012		)	(2,193		)	(5,386		)	(5,424		)
Proceeds from sale of assets	11			22			241			200
Net cash used in investing activities	(3,001		)	(2,171		)	(5,145		)	(5,224		)
Cash flows from financing activities
Net (payments) borrowings under credit agreements	(176,740		)	22,482
Net payments under credit agreements							(131,618		)	(96,973		)
Payments on finance leases, term debt, and other obligations	(1,586		)	(1,212		)	(2,804		)	(2,261		)
Debt issue costs							(5,669		)	—
Distributions to unitholders	(15,184		)	(17,230		)	(32,557		)	(34,460		)
Repurchased units withheld for employee tax obligations	(297		)	—			(297		)	—
Net cash (used in) provided by financing activities	(193,807		)	4,040
Net cash used in financing activities							(172,945		)	(133,694		)
Effect of exchange rate changes on cash balances held in foreign currencies	(124		)	33			(829		)	18
Net change in cash and cash equivalents	4,169			(1,073		)	(1,638		)	(1,430		)
Cash and cash equivalents, beginning of period	5,386			7,530			5,386			7,530
Cash and cash equivalents, end of period	$	9,555		$	6,457		$	3,748		$	6,100
Supplemental disclosure of cash flow information
Cash paid for interest	$	10,883		$	10,803		$	20,424		$	20,195
Cash paid for taxes	$	1,374		$	2,901		$	1,434		$	5,679
Assets acquired under finance lease obligations	$	273		$	702		$	609		$	1,179
ROU assets obtained in exchange for new lease liabilities	$	—		$	424		$	—		$	630
Cash paid for operating leases	$	2,551		$	2,233		$	3,085		$	2,510
Distribution paid in units	$	2,072		$	—		$	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.

Unless the context otherwise requires, references 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.

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~~4 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 ~~March 31,~~June 30, 2020, the Sponsor, through its ownership of Sprague Holdings, owned ~~12,227,498~~12,951,236 common units representing ~~53%~~56.5% of the limited partner interest in the Partnership. 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 $0.474375 per unit per quarter. 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.

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, 2019 as filed with the SEC on March 5, 2020 (the “2019 Annual Report”).

Table of Contents

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 ~~March 31,~~June 30, 2020 and December 31, 2019, the consolidated results of operations for the three and six months ended ~~March 31,~~June 30, 2020 and 2019, and the consolidated cash flows for the ~~three~~six months ended ~~March 31,~~June 30, 2020 and 2019. 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 and stay-at-home orders, 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, further exacerbated by recent disagreements regarding crude oil production levels between the Organization of Petroleum Exporting Countries (OPEC) members and other oil-producing countries such as Russia, as well as related global storage considerations. Although Saudi Arabia and Russia reached an agreement to reduce output in early April, prices remained much lower than last year.

~~While the~~The pandemic and associated impacts on economic activity had ~~a limited~~an adverse effect on the Partnership’s operating results for the ~~quarterly period~~three and six months ended ~~March 31,~~June 30, 2020, specifically, the Partnership has ~~since~~ seen ~~an increasing~~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, in March 2020, 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 ~~March 31,~~June 30, 2020. At this time, the Partnership is unable to predict with specificity the ultimate impact of the crisis, as it will depend on the magnitude, severity and duration of the pandemic, as well as how quickly, and to what extent, normal economic and operating conditions resume on a sustainable basis globally. Accordingly, if the impact is more severe or longer in duration than the Partnership has assumed, such impact could potentially result in impairments and increases in credit allowances.

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 2019 Annual Report and are the same as are used in preparing these unaudited interim Condensed Consolidated Financial Statements, except with respect to the Partnership’s policy on credit losses noted within the “Recent Accounting Pronouncements” section below.

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Recent Accounting Pronouncements

In June 2016, the FASB issued ASU 2016-13, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments. The standard requires entities to use a forward-looking approach based on expected losses rather than incurred losses to estimate credit losses on certain types of financial instruments, including trade receivables. This may result in the earlier recognition of allowances for losses. The guidance is effective for interim and annual periods for fiscal years beginning after December 15, 2019, with early adoption permitted. As part of the Partnership’s assessment of the adequacy of its allowances for credit losses, the Partnership consider a number of factors including, but not limited to, history or defaults, age of receivables, and expected loss rates. The adoption of this guidance did not have a material impact to the Partnership's Condensed Consolidated Financial Statements.

In January 2017, the FASB issued ASU 2017-04, Intangibles - Goodwill and Other (Topic 350): Simplifying the Accounting for Goodwill Impairment. The guidance removes Step 2 of the goodwill impairment test, which requires a hypothetical purchase price allocation. A goodwill impairment will now be the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill. The standard will be applied prospectively, and is effective for fiscal years beginning after December 15, 2019. The adoption of this guidance did not have a material impact to the Partnership's Condensed Consolidated Financial Statements.

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 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.

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.

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



	Three Months Ended June 30,				Six Months Ended June 30,
	2020		2019		2020		2019
Net sales:
Refined products
Distillates	$	219,599	$	452,688	$	915,427	$	1,416,705
Gasoline	43,688		73,815		119,965		133,156
Heavy fuel oil and asphalt	29,602		57,810		99,439		154,575
Total refined products	$	292,889	$	584,313	$	1,134,831	$	1,704,436
Natural gas	47,988		58,108		143,766		172,275
Materials handling	12,974		14,313		28,531		30,794
Other operations	4,363		5,284		10,965		12,821
Net sales	$	358,214	$	662,018	$	1,318,093	$	1,920,326

Net sales by Country:
United States	$	324,058	$	600,732	$	1,230,867	$	1,803,423
Canada	34,156		61,286		$	87,226	116,903
Net sales	$	358,214	$	662,018	$	1,318,093	$	1,920,326

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Three Months Ended March 31,
2020 2019
Net sales:
Refined products
Distillates $ 695,828
$ 964,017
Gasoline 76,277
59,341
Heavy fuel oil and asphalt 69,837
96,765
Total refined products $ 841,942
$ 1,120,123
Natural gas 95,778
114,167
Materials handling 15,557
16,481
Other operations 6,602
7,537
Net sales $ 959,879
$ 1,258,308

Net sales by Country:
United States $ 906,809
$ 1,202,691
Canada 53,070
55,617
Net sales $ 959,879
$ 1,258,308

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 ~~$6.0~~$7.5 million and $7.5 million as of ~~March 31,~~June 30, 2020 and December 31, 2019, respectively. A substantial portion of the contract liabilities as of December 31, 2019 remains outstanding as of ~~March 31,~~June 30, 2020 as they are primarily deposits. The Partnership does not have any material contract assets as of ~~March 31,~~June 30, 2020 or December 31, 2019.

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. ~~For the three months ended March 31, 2020 and 2019, income~~Income related to the operating leases with the Partnership as the lessor, as described above, totaled ~~$9.4~~$10.8 million and ~~$11.0~~$10.6 million for the three months ended June 30, 2020 and 2019, respectively, and $20.3 million and $21.6 million for the six months ended June 30, 2020 and 2019, respectively.

4. Accumulated Other Comprehensive Loss, Net of Tax

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



	June 30, 2020			December 31, 2019
Fair value of interest rate swaps, net of tax	$	(15,819	)	$	(8,150	)
Cumulative foreign currency translation adjustment	(11,729		)	(11,538		)
Accumulated other comprehensive loss, net of tax	$	(27,548	)	$	(19,688	)

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March 31,
2020 December 31, 2019
Fair value of interest rate swaps, net of tax $ (16,002 ) $ (8,150 )
Cumulative foreign currency translation adjustment (11,852 ) (11,538 )
Accumulated other comprehensive loss, net of tax $ (27,854 ) $ (19,688 )

5. Inventories



	June 30, 2020		December 31, 2019
Petroleum and related products	$	191,871	$	285,539
Coal	3,316		4,374
Natural gas	1,252		3,311
Inventories	$	196,439	$	293,224

March 31,
2020 December 31,
2019
Petroleum and related products $ 104,901
$ 285,539
Coal 4,401
4,374
Natural gas 624
3,311
Inventories $ 109,926
$ 293,224

6. Credit Agreement



	June 30, 2020			December 31, 2019
Working capital facilities	$	288,054		$	437,184
Acquisition facility	392,000			374,600
Total credit agreement	680,054			811,784
Less: current portion of working capital facilities	(288,054		)	(437,184		)
Long-term portion	$	392,000		$	374,600

March 31,
2020 December 31, 2019
Working capital facilities $ 282,900
$ 437,184
Acquisition facility 352,000
374,600
Total credit agreement 634,900
811,784
Less: current portion of working capital facilities (282,900 ) (437,184 )
Long-term portion $ 352,000
$ 374,600

On May 19, 2020, Sprague Operating Resources LLC (the “U.S. Borrower”) and Kildair Service ULC ~~("Kildair"~~(the “Canadian Borrower” and, together with the U.S. Borrower, the “Borrowers”), wholly owned subsidiaries of the Partnership, ~~are borrowers under an~~entered into a second amended and restated ~~revolving~~ credit agreement (the ~~"Credit Agreement"~~“Credit Agreement”) ~~that~~, which replaced the amended and restated credit agreement, dated December 9, 2014 (the “Previous Credit Agreement”). Upon the effective date, the Credit Agreement was accounted for as a modification of a syndicated loan arrangement with partial extinguishment to the extent of the decrease in the borrowing capacity. The Credit Agreement matures on ~~April 27, 2021.~~May 19, 2022. 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 ~~its subsidiaries.~~the Subsidiary Guarantors (collectively, the “Loan Parties”).

As of ~~March 31,~~June 30, 2020, 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 ~~$950.0~~$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 ~~$100.0~~$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 ~~$550.0~~$430.0 million, subject to ~~the acquisition facility~~ borrowing base limits, to be used for loans and letters of credit to fund capital expenditures and acquisitions and other general corporate ~~purposes related to the Partnership’s current businesses,~~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 ~~by $250.0 million~~to up to $1.2 billion and the multicurrency revolving working capital facility ~~by $220.0~~to up to $320.0 million, subject to a maximum combined increase in commitments for both facilities of ~~$270.0~~$470.0 million in the aggregate. Additionally, subject to certain conditions, the revolving acquisition facility may be increased ~~by $200.0~~to up to $750.0 million.

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Indebtedness under the Credit Agreement bears interest, at the ~~borrowers’~~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)~~costs, and in each case with a floor of 0.50%) for interest periods of one, two, three or six 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%.

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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. On or prior to November 19, 2020, the specified margin for (x) the committed U.S. dollar revolving working capital facility will range from 1.25% to 1.75% for loans bearing interest at the Base Rate and from 2.25% to 2.75% for loans bearing interest at the Eurocurrency Rate, (y) the uncommitted U.S. dollar revolving working capital facility will 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 and (z) the multicurrency revolving working capital facility will range from 1.25% to 1.75% for loans bearing interest at the Base Rate and 2.25% to 2.75% for loans bearing interest at the Eurocurrency Rate. After November 19, 2020, the specified margin for (x) the committed U.S. dollar revolving working capital facility will range from 0.75% to 1.25% for loans bearing interest at the Base Rate and from 1.75% to 2.25% for loans bearing interest at the Eurocurrency Rate, (y) the uncommitted U.S. dollar revolving working capital facility will range from 0.50% to 1.00% for loans bearing interest at the Base Rate and 1.50% to 2.00% for loans bearing interest at the Eurocurrency Rate and (z) the multicurrency revolving working capital facility will 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.

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 ~~March 31,~~June 30, 2020 and December 31, 2019, the Credit Agreement had a borrowing base of ~~$376.5~~$379.9 million and the Previous Credit Agreement had a borrowing base of $594.5 million, respectively. As of ~~March 31,~~June 30, 2020 and December 31, 2019, outstanding letters of credit were ~~$41.0~~$14.7 million under the Credit Agreement and $63.6 million under the Previous Credit Agreement, respectively. As of ~~March 31,~~June 30, 2020, excess availability under the working capital facilities was ~~$52.6~~$77.1 million and excess availability under the acquisition facility was ~~$198.0~~$38.0 million.

The weighted average interest rate was ~~3.8%~~3.4% under the Credit Agreement and 4.5% under the Previous Credit Agreement at ~~March 31,~~June 30, 2020 and December 31, 2019, respectively. No amounts are due under the Credit Agreement until the maturity date. However, the current portion of the Credit Agreement at ~~March 31,~~June 30, 2020 and the current portion of the Previous Credit Agreement at December 31, 2019 represents the amounts of the working capital ~~facility during the following twelve month period.~~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 ~~Partnership~~Loan Parties would not be in pro forma compliance with ~~its~~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 ~~Partnership~~Loan Parties to maintain: a minimum consolidated EBITDA-to ~~fixed charge~~fixed-charge ratio, a minimum consolidated net working capital amount and a maximum consolidated total ~~leverage-to-EBITDA~~

~~ratio and a maximum consolidated senior secured leverage-to-EBITDA ratio.~~leverage-to-EBITDA. The Credit Agreement also limits the

~~Partnership's~~ Loan Parties ability to incur debt, grant liens, make certain investments or acquisitions, enter into affiliate transactions and dispose of ~~assets, and incur additional~~

~~indebtedness.~~assets. The Partnership was in compliance with the covenants under the Credit Agreement at ~~March 31,~~June 30, 2020.

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 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.

The Credit Agreement, which matures on April 27, 2021, has not yet been renewed and, therefore, is due within one year of the date of issuance of these condensed consolidated financial statements. While the Partnership does not currently have the liquidity to repay the debt associated with the Credit Agreement at maturity, the Partnership is presently in discussions with a consortium of banking partners to refinance and extend the Credit Agreement for a new term. The Partnership’s ongoing approved plan to renew the Credit Agreement is probable of being effectuated based on the status of the current negotiations and the fact that the Company has successfully extended the maturity date of the Credit Agreement on a historical basis.

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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 ~~$23.5~~$21.0 million and $~~28.1~~23.7 million for the three months ended ~~March 31,~~June 30, 2020 and 2019, respectively, and $44.5 million and $51.8 million for the six months ended June 30, 2020 and 2019, respectively. Through the General Partner, the Partnership also participates in the

Sponsor’s pension and other post-retirement benefits. At ~~March 31,~~June 30, 2020 and December 31, 2019, total amounts due to the General Partner with respect to these benefits and overhead costs were ~~$7.6~~$7.0 million and $8.1 million, respectively.

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8. Segment Reporting

The Partnership has ~~four~~4 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 and educational institutions. The refined products reportable segment consists of ~~two~~2 operating segments.

The Partnership's natural gas segment purchases natural gas from natural gas producers and trading companies and sells and distributes natural gas to commercial and industrial customers primarily in the Northeast and Mid-Atlantic United States. The natural gas reportable segment consists of ~~one~~1 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 provided 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~~2 operating segments.

The Partnership's other operations segment primarily consists of marketing 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~~2 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 ~~March 31,~~June 30, 2020 and 2019, respectively. The Partnership’s foreign sales, primarily sales of refined products and natural gas to its customers in Canada, were ~~$53.1~~$34.2 million and ~~$55.6~~$61.3 million for the three months ended ~~March 31,~~June 30, 2020 and 2019, respectively, and $87.2 million and $116.9 million for the six months ended June 30, 2020 and 2019, respectively.

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


	Three Months Ended March 31,						Three Months Ended June 30,						Six Months Ended June 30,
	2020			2019			2020			2019			2020			2019
Net sales:
Refined products	$	841,942		$	1,120,123		$	292,889		$	584,313		$	1,134,831		$	1,704,436
Natural gas	95,778			114,167			47,988			58,108			143,766			172,275
Materials handling	15,557			16,481			12,974			14,313			28,531			30,794
Other operations	6,602			7,537			4,363			5,284			10,965			12,821
Net sales	$	959,879		$	1,258,308		$	358,214		$	662,018		$	1,318,093		$	1,920,326
Adjusted gross margin (1):
Refined products	$	35,792		$	44,739		$	52,861		$	27,646		$	88,650		$	72,384
Natural gas	29,787			32,322			(2,245		)	4,647			27,542			36,968
Materials handling	15,581			16,451			12,895			14,334			28,476			30,785
Other operations	1,951			1,932			1,673			1,649			3,626			3,581
Adjusted gross margin	83,111			95,444			65,184			48,276			148,294			143,718
Reconciliation to operating income (2):
Add/(deduct):
Change in unrealized gain on inventory (3)	13,549			(4,236		)	(32,326		)	(364		)	(18,775		)	(4,598		)
Change in unrealized value on natural gas transportation contracts (4)	13,199			7,988			123			5,446			13,322			13,434
Operating costs and expenses not allocated to operating segments:
Operating expenses	(20,812		)	(23,789		)	(18,471		)	(21,075		)	(39,283		)	(44,864		)
Selling, general and administrative	(20,033		)	(20,913		)	(18,923		)	(17,827		)	(38,956		)	(38,739		)
Depreciation and amortization	(8,598		)	(8,388		)	(8,518		)	(8,408		)	(17,115		)	(16,797		)
Operating income	60,416			46,106
Operating (loss) income							(12,931		)	6,048			47,487			52,154
Other income							64			128			64			128
Interest income	175			187			72			140			248			326
Interest expense	(11,286		)	(11,959		)	(10,788		)	(10,038		)	(22,074		)	(21,997		)
Income tax provision	(2,571		)	(413		)	(1,542		)	(1,056		)	(4,113		)	(1,469		)
Net income	$	46,734		$	33,921
Net (loss) income							$	(25,125	)	$	(4,778	)	$	21,612		$	29,142

(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 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.


(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 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.

(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 (loss).

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 no0 significant fixed assets attributable to the natural gas reportable segment.

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As of ~~March 31,~~June 30, 2020, 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.

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9. Financial Instruments and Off-Balance Sheet Risk

As of ~~March 31,~~June 30, 2020 and December 31, 2019, the carrying amounts of cash, cash equivalents, accounts receivable, accounts payable and accrued liabilities approximated fair value because of the short maturity of these instruments. As of ~~March 31,~~June 30, 2020 and December 31, 2019, 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 ~~March 31,~~June 30, 2020 and December 31, 2019, the carrying value of the Partnership’s debt approximated fair value due to the variable interest nature of these instruments.

The Partnership’s deferred consideration was recorded in connection with an acquisition on April 18, 2017 using an estimated fair value discount at the time of the transaction. As of ~~March 31,~~June 30, 2020, the carrying value of the deferred consideration approximated fair value because there has been no significant subsequent change in the estimated fair value discount rate or probability of outcome.

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


	As of March 31, 2020								As of June 30, 2020
	Fair Value Measurement		Quoted Prices in Active Markets Level 1		Significant Other Observable Inputs Level 2		Significant Unobservable Inputs Level 3		Fair Value Measurement		Quoted Prices in Active Markets Level 1		Significant Other Observable Inputs Level 2		Significant Unobservable Inputs Level 3
Derivative assets:
Commodity exchange contracts	$	15	$	15	$	—	$	—
Commodity fixed forwards	130,918		—		130,918		—		$	91,264	$	—	$	91,264	$	—
Futures, swaps and options	248,031		248,012		19		—		130,466		130,461		5		—
Commodity derivatives	378,964		248,027		130,937		—		221,730		130,461		91,269		—
Currency swaps	3		—		3		—
Total derivative assets	$	378,967	$	248,027	$	130,940	$	—	$	221,730	$	130,461	$	91,269	$	—
Derivative liabilities:
Commodity fixed forwards	$	7,507	$	—	$	7,507	$	—	$	15,949	$	—	$	15,949	$	—
Futures, swaps and options	237,962		237,916		46		—		160,823		160,821		2		—
Commodity derivatives	245,469		237,916		7,553		—		176,772		160,821		15,951		—
Interest rate swaps	16,128		—		16,128		—		15,943		—		15,943		—
Currency swaps									6		—		6		—
Total derivative liabilities	$	261,597	$	237,916	$	23,681	$	—	$	192,721	$	160,821	$	31,900	$	—

Contingent consideration	$	7,710	$	—	$	—	$	7,710	$	7,833	$	—	$	—	$	7,833

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	As of December 31, 2019
	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	$	62,580	$	—	$	62,580	$	—
Futures, swaps and options	32,083		32,057		26		—
Commodity derivatives	94,663		32,057		62,606		—
Currency swaps	15		—		15		—
Total derivative assets	$	94,678	$	32,057	$	62,621	$	—
Derivative liabilities:
Commodity exchange contracts	$	2	$	2	$	—	$	—
Commodity fixed forwards	16,017		—		16,017		—
Futures, swaps and options	63,360		63,359		1		—
Commodity derivatives	79,379		63,361		16,018		—
Interest rate swaps	8,214		—		8,214		—
Total derivative liabilities	$	87,593	$	63,361	$	24,232	$	—

Contingent consideration	$	7,590	$	—	$	—	$	7,590

As of December 31, 2019
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 $ 62,580
$ —
$ 62,580
$ —
Futures, swaps and options 32,083
32,057
26
—
Commodity derivatives 94,663
32,057
62,606
—
Currency swaps 15
—
15
—
Total derivative assets $ 94,678
$ 32,057
$ 62,621
$ —
Derivative liabilities:
Commodity exchange contracts $ 2
$ 2
$ —
$ —
Commodity fixed forwards 16,017
—
16,017
—
Futures, swaps and options 63,360
63,359
1
—
Commodity derivatives 79,379
63,361
16,018
—
Interest rate swaps 8,214
—
8,214
—
Total derivative liabilities $ 87,593
$ 63,361
$ 24,232
$ —

Contingent consideration $ 7,590
$ —
$ —
$ 7,590

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. A majority of all of the Partnership’s commodity derivative contracts outstanding as of ~~March 31,~~June 30, 2020 will settle prior to ~~September 30,~~December 31, 2021.

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 (loss) 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.

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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.

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 utilizes fair value measurements based on Level 3 inputs for its contingent consideration obligation.

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 ~~March 31,~~June 30, 2020 and December 31, 2019.

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 ~~$158.1~~$92.3 million at ~~March 31,~~June 30, 2020. Information related to these offsetting arrangements is set forth below:


	As of March 31, 2020												As of June 30, 2020
				Gross Amount Not Offset in the Balance Sheet												Gross Amount Not Offset in the Balance Sheet
	Gross Amount of Assets/Liabilities in the Balance Sheet			Financial Instruments			Cash Collateral Posted			Net Amount			Gross Amount of Assets/Liabilities in the Balance Sheet			Financial Instruments			Cash Collateral Posted			Net Amount
Commodity derivative assets	$	378,964		$	(220,822	)	$	(21,336	)	$	136,806		$	221,730		$	(129,457	)	$	(2,434	)	$	89,839
Currency swaps	3			—			—			3
Fair value of derivative assets	$	378,967		$	(220,822	)	$	(21,336	)	$	136,809		$	221,730		$	(129,457	)	$	(2,434	)	$	89,839

Commodity derivative liabilities	$	(245,469	)	$	220,822		$	18,751		$	(5,896	)	$	(176,772	)	$	129,457		$	33,445		$	(13,870	)
Interest rate swap derivative liabilities	(16,128		)	—			—			(16,128		)	(15,943		)	—			—			(15,943		)
Currency swaps													(6		)	—			—			(6		)
Fair value of derivative liabilities	$	(261,597	)	$	220,822		$	18,751		$	(22,024	)	$	(192,721	)	$	129,457		$	33,445		$	(29,819	)

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	As of December 31, 2019
				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	$	94,663		$	(36,885	)	$	—	$	57,778
Currency swaps	15			—			—		15
Fair value of derivative assets	$	94,678		$	(36,885	)	$	—	$	57,793

Commodity derivative liabilities	$	(79,379	)	$	36,885		$	31,303	$	(11,191	)
Interest rate swap derivative liabilities	(8,214		)	—			—		(8,214		)
Fair value of derivative liabilities	$	(87,593	)	$	36,885		$	31,303	$	(19,405	)

As of December 31, 2019
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 $ 94,663
$ (36,885 ) $ —
$ 57,778
Currency swaps 15
—
—
15
Fair value of derivative assets $ 94,678
$ (36,885 ) $ —
$ 57,793

Commodity derivative liabilities $ (79,379 ) $ 36,885
$ 31,303
$ (11,191 )
Interest rate swap derivative liabilities (8,214 ) —
—
(8,214 )
Fair value of derivative liabilities $ (87,593 ) $ 36,885
$ 31,303
$ (19,405 )

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,
	2020			2019			2020		2019
Refined products contracts	$	(8,869	)	$	(5,513	)	$	57,336	$	(21,896	)
Natural gas contracts	3,332			10,688			39,345		24,067
Total	$	(5,537	)	$	5,175		$	96,681	$	2,171

Three Months Ended March 31,
2020 2019
Refined products contracts $ 66,205
$ (16,383 )
Natural gas contracts 36,013
13,379
Total $ 102,218
$ (3,004 )

There were no discretionary trading activities for the three and six months ended ~~March 31,~~June 30, 2020 and 2019. The following table presents gross volume of commodity derivative instruments outstanding for the periods indicated:



	As of June 30, 2020				As of December 31, 2019
	Refined Products (Barrels)		Natural Gas (MMBTUs)		Refined Products (Barrels)		Natural Gas (MMBTUs)
Long contracts	18,667		178,485		8,332		168,818
Short contracts	(23,261	)	(94,392	)	(11,475	)	(91,011	)

As of March 31, 2020 As of December 31, 2019

Refined Products
(Barrels)

Natural Gas
(MMBTUs)

Refined Products
(Barrels)

Natural Gas
(MMBTUs)
Long contracts 15,433
175,460
8,332
168,818
Short contracts (18,014 ) (92,733 ) (11,475 ) (91,011 )

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 interest rate risk associated with LIBOR based 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 our exposure to LIBOR interest rates or its replaced equivalent for the foreseeable future.

The Partnership's interest rate swap agreements outstanding as of ~~March 31,~~June 30, 2020 were as follows:



Beginning	Ending	Notional Amount
January 2020	January 2021	$	300,000
April 2020	April 2021	$	25,000
January 2021	January 2022	$	300,000
April 2021	April 2022	$	25,000
January 2022	January 2023	$	250,000
April 2022	April 2023	$	25,000

Beginning Ending Notional Amount
January 2020 January 2021 $ 300,000
January 2021 January 2022 $ 300,000
January 2022 January 2023 $ 250,000

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 ~~March 31,~~June 30, 2020, the amount of unrealized losses, net of tax, expected to be reclassified to earnings during the following twelve-month period was ~~$6.5~~$7.1 million.

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Contingent Consideration

As part of the Coen Energy acquisition in 2017, the Partnership is obligated to pay contingent consideration of up to $12.0 million if certain earnings objectives during the first three years following the acquisition are met. The estimated fair value of the contingent consideration arrangement is classified within Level 3 and was determined using an income approach based on probability-weighted discounted cash flows. Under this method, a set of discrete potential future earnings was determined using internal estimates based on various revenue growth rate assumptions for each scenario. A probability was assigned to each discrete potential future earnings estimate. The resulting probability-weighted contingent consideration amounts were discounted using a weighted average discount rate of 7.0%. Changes in either the revenue growth rates, related earnings or the discount rate could result in a material change to the amount of contingent consideration accrued and such changes will be recorded in the Partnership's Condensed Consolidated Income Statements.

The Partnership records changes in the estimated fair value of the contingent consideration within selling, general and administrative expenses in the Condensed Consolidated Income Statements. Changes in the contingent consideration liability are measured at fair value on a recurring basis using unobservable inputs (Level 3) are as follows:



Contingent consideration - December 31, 2019	$	7,590	$	7,590
Change in estimated fair value	120		243
Contingent consideration - March 31, 2020	$	7,710
Contingent consideration - June 30, 2020			$	7,833

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 a recent 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 ~~$4.7~~$6.2 million of tax, including interest and penalties, for the period of 2007 to 2018. Similarly, since the filing, the Partnership has been assessed ~~$8.5~~$9.0 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 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.

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.

~~Table of Contents~~

11. Equity and Equity-Based Compensation

Equity Awards - Performance-based Phantom Units

The board of directors of the General Partner grants performance-based phantom unit awards to key employees that vest 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.

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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.

The following table presents a summary of the Partnership’s phantom unit awards subject to vesting during the ~~three~~six months ended ~~March 31,~~June 30, 2020:



	2019 Awards					2018 Awards
	Units		Weighted Average Grant Date Fair Value (per unit)			Units		Weighted Average Grant Date Fair Value (per unit)
Nonvested at December 31, 2019	163,531		$	15.04		110,993		$	23.30
Granted	—		—			—		—
Forfeited	(4,444	)	(15.04		)	(797	)	(23.30		)
Vested (end of performance period)	—		—			—		—
Nonvested at June 30, 2020	159,087		$	15.04		110,196		$	23.30

2019 Awards 2018 Awards
Units
Weighted
Average
Grant Date
Fair Value
(per unit)
Units Weighted
Average
Grant Date
Fair Value
(per unit)
Nonvested at December 31, 2019 163,531
$ 15.04
110,993
$ 23.30
  Granted —
—
—
—
  Forfeited (1,000 ) (15.04 ) —
—
  Vested (end of performance period) —
—
—
—
Nonvested at March 31, 2020 162,531
$ 15.04
110,993
$ 23.30

Unit-based compensation expense (income) for the ~~three~~six months ended ~~March 31,~~June 30, 2020 was ~~$0.4~~$1.3 million as compared to ~~$(0.2)~~$(0.1) million for the ~~three~~six months ended ~~March 31,~~June 30, 2019. The ~~board~~increase is due to a change in estimate recorded in June 30, 2019 which resulted in a reversal of ~~directors of the General Partner is evaluating other alternatives to replace the 2019 long term incentive program for 2020.~~stock based compensation expense during 2019.

Unit-based compensation is included in selling, general and administrative expenses. Unrecognized compensation cost related to performance-based phantom units totaled ~~$1.3~~$1.7 million as of ~~March 31,~~June 30, 2020 which is expected to be recognized over a weighted average period of 2118 months.

Equity - Changes in Partnership Units

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



	Common Units
	Public		Sprague Holdings
Balance as of December 31, 2018	10,627,629		12,106,348
Director vested awards	13,932		—
Balance as of December 31, 2019	10,641,561		12,106,348
Units issued in connection with employee bonus	53,843		—
Distribution paid in units	—		121,150
Units purchased by Sprague Holdings in private transaction	(723,738	)	723,738
Balance as of June 30, 2020	9,971,666		12,951,236

Common Units
Public
Sprague
Holdings
Balance as of December 31, 2018 10,627,629
12,106,348
Director vested awards 13,932
—
Balance as of December 31, 2019 10,641,561
12,106,348
Units issued in connection with employee bonus 53,843
—
Distribution paid in units —
121,150
Balance as of March 31, 2020 10,695,404
12,227,498

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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 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.

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. Quarterly net income per limited partner and per unit amounts are stand-alone calculations and may not be additive to year to date amounts due to rounding and changes in outstanding units.

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,
	2020	2019	2020	2019
Weighted average limited partner common units - basic	22,922,902	22,733,977	22,871,943	22,733,977
Dilutive effect of unvested phantom units	—	—	65,330	20,579
Weighted average limited partner common units - dilutive	22,922,902	22,733,977	22,937,273	22,754,556

Three Months Ended March 31,
2020 2019
Weighted average limited partner common units - basic 22,820,983
22,733,977
Dilutive effect of unvested phantom units 50,765
5,632
Weighted average limited partner common units - dilutive 22,871,748
22,739,609

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. Payments made in connection with DERs are recorded as a distribution.

Cash distributions for the periods indicated were as follows:



Quarter Ended	Payment Date	Per Unit	Common		IDR			Total
December 31, 2019	February 10, 2020	$0.6675	$	15,184	$	2,053	(1)	$	17,236
March 31, 2020	May 11, 2020	$0.6675	$	15,301	$	2,072		$	17,373

Quarter Ended Payment Date Per Unit Common IDR (1) Total
December 31, 2019 February 10, 2020 $0.6675 $ 15,184
$ 2,072
$ 17,256


(1)	On February 10, 2020, the Sponsor received 121,150 common units, in lieu of cash, in respect of the incentive distribution rights payable in connection with the distribution for the fourth quarter of 2019.

In addition, on ~~April~~July 24, 2020, the Partnership declared a cash distribution for the three months ended ~~March 31,~~June 30, 2020, of $0.6675 per unit, totaling $17.4 million (including a $2.1 million IDR distribution). Such distributions are to be paid on ~~May 11,~~August 10, 2020, to unitholders of record on ~~May 5,~~August 4, 2020.

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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, 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. Our General Partner is a wholly owned subsidiary of Axel Johnson.

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. 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 recent 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, 2019, as filed with the U.S. Securities and Exchange Commission (“SEC”) on March 5, 2020 (the “2019 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.

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 14.3 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 900 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 ~~14,000~~15,000 commercial and industrial customer locations across 13 states in the Northeast and Mid-Atlantic United States.

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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As of ~~March 31,~~June 30, 2020, our Sponsor, through its ownership of Sprague Holdings, owns ~~12,227,498~~12,951,236 common units representing an aggregate of ~~53%~~56.5% of the limited partner interest in the Partnership. 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 $0.474375 per unit per quarter. 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

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 COVID-19 pandemic. A growing number of our customers in these industries have experienced substantial reductions in their operations due to travel restrictions and stay-at-home orders, 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, further exacerbated by recent disagreements regarding crude oil production levels between the Organization of Petroleum Exporting Countries (OPEC) members and other oil-producing countries such as Russia, as well as related global storage considerations. Although Saudi Arabia and Russia reached an agreement to reduce output in early April, prices remained much lower than last year.

~~While the~~The pandemic and associated impacts on economic activity had ~~a limited~~an adverse effect on our operating results for the ~~quarterly period~~three and six months ended ~~March 31,~~June 30, 2020, specifically, we have ~~since~~ seen ~~an increasing~~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, in March 2020, we 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.

At this time, we are unable to predict with specificity the ultimate impact of the crisis, as it will depend on the magnitude, severity and duration of the pandemic, as well as how quickly, and to what extent, normal economic and operating conditions resume on a sustainable basis globally. We continue to work with our customers, employees, suppliers and communities to address the impacts of COVID-19. In addition, we continue to assess possible implications to our business, supply chain and customers, and to take actions in an effort to mitigate adverse consequences.

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, adjusted for the impact of acquisition related expenses, and adjusted for the impact of biofuel excise tax credits resulting from retroactive tax legislation changes that occurred in 2018.

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;

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

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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

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 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. In determining adjusted gross margin, management adjusts its segment results for the impact of 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 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.

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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.

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

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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 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 2019 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 March 31,						Increase/(Decrease)					Three Months Ended June 30,						Increase/(Decrease)
	2020			2019			$			%		2020			2019			$			%
	(in thousands)											(in thousands)
Net sales	$	959,879		$	1,258,308		$	(298,429	)	(24	)%	$	358,214		$	662,018		$	(303,804	)	(46	)%
Cost of products sold (exclusive of depreciation and amortization)	850,020			1,159,112			(309,092		)	(27	)%	325,233			608,660			(283,427		)	(47	)%
Operating expenses	20,812			23,789			(2,977		)	(13	)%	18,471			21,075			(2,604		)	(12	)%
Selling, general and administrative	20,033			20,913			(880		)	(4	)%	18,923			17,827			1,096			6	%
Depreciation and amortization	8,598			8,388			210			3	%	8,518			8,408			110			1	%
Total operating costs and expenses	899,463			1,212,202			(312,739		)	(26	)%	371,145			655,970			(284,825		)	(43	)%
Operating income	60,416			46,106			14,310			31	%
Operating (loss) income												(12,931		)	6,048			(18,979		)	(314	)%
Other income												64			128			(64		)	(50	)%
Interest income	175			187			(12		)	(6	)%	72			140			(68		)	(49	)%
Interest expense	(11,286		)	(11,959		)	661			(6	)%	(10,788		)	(10,038		)	(818		)	8	%
Income before income taxes	49,305			34,334			14,971			44	%
Loss before income taxes												(23,583		)	(3,722		)	(19,861		)	534	%
Income tax provision	(2,571		)	(413		)	(2,158		)	523	%	(1,542		)	(1,056		)	(486		)	46	%
Net income	$	46,734		$	33,921		$	12,813		38	%
Net loss												$	(25,125	)	$	(4,778	)	$	(20,347	)	426	%




	Six Months Ended June 30,						Increase/(Decrease)
	2020			2019			$			%
	(in thousands)
Net sales	$	1,318,093		$	1,920,326		$	(602,233	)	(31	)%
Cost of products sold (exclusive of depreciation and amortization)	1,175,252			1,767,772			(592,520		)	(34	)%
Operating expenses	39,283			44,864			(5,581		)	(12	)%
Selling, general and administrative	38,956			38,739			217			1	%
Depreciation and amortization	17,115			16,797			318			2	%
Total operating costs and expenses	1,270,606			1,868,172			(597,566		)	(32	)%
Operating income	47,487			52,154			(4,667		)	(9	)%
Other income	64			128			(64		)	—	%
Interest income	248			326			(78		)	(24	)%
Interest expense	(22,074		)	(21,997		)	(155		)	1	%
Income before income taxes	25,725			30,611			(4,886		)	(16	)%
Income tax provision	(4,113		)	(1,469		)	(2,644		)	180	%
Net income	$	21,612		$	29,142		$	(7,530	)	(26	)%

~~Analysis of Consolidated Operating Results~~

Net income was $46.7 million and $33.9 million for the three months ended March 31, 2020 and 2019, respectively and operating income was $60.4 million and $46.1 million for the three months ended March 31, 2020 and 2019, respectively. Operating results for the three months ended March 31, 2020 and 2019 include unrealized commodity derivative gains and losses with respect to refined products and natural gas inventory and natural gas transportation contracts of $26.7 million and $3.8 million, respectively. Excluding these unrealized items, operating income for the three months ended March 31, 2020 decreased $8.7 million, or 21%, as compared to the three months ended March 31, 2019.

~~See "Analysis of Operating Segments", "Operating Costs and Expenses" and "Liquidity and Capital Resources" below for additional details on our operating results.~~

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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 March 31,						Three Months Ended June 30,						Six Months Ended June 30,
	2020			2019			2020			2019			2020			2019
	(in thousands)						(in thousands)
Reconciliation of Operating Income to Adjusted Gross Margin:	Reconciliation of Operating Income to Adjusted Gross Margin:						Reconciliation of Operating Income to Adjusted Gross Margin:
Operating income	$	60,416		$	46,106
Operating (loss) income							$	(12,931	)	$	6,048		$	47,487		$	52,154
Operating costs and expenses not allocated to operating segments:
Operating expenses	20,812			23,789			18,471			21,075			39,283			44,864
Selling, general and administrative	20,033			20,913			18,923			17,827			38,956			38,739
Depreciation and amortization	8,598			8,388			8,518			8,408			17,115			16,797
Add/(deduct):
Change in unrealized (loss) gain on inventory (1)	(13,549		)	4,236			32,326			364			18,775			4,598
Change in unrealized value on natural gas transportation contracts (2)	(13,199		)	(7,988		)	(123		)	(5,446		)	(13,322		)	(13,434		)
Total adjusted gross margin (3):	$	83,111		$	95,444		$	65,184		$	48,276		$	148,294		$	143,718
Adjusted Gross Margin by Segment:
Refined products	$	35,792		$	44,739		$	52,861		$	27,646		$	88,650		$	72,384
Natural gas	29,787			32,322			(2,245		)	4,647			27,542			36,968
Materials handling	15,581			16,451			12,895			14,334			28,476			30,785
Other operations	1,951			1,932			1,673			1,649			3,626			3,581
Total adjusted gross margin	$	83,111		$	95,444		$	65,184		$	48,276		$	148,294		$	143,718
Reconciliation of Net Income to Adjusted EBITDA
Net income	$	46,734		$	33,921
Net (loss) income							$	(25,125	)	$	(4,778	)	$	21,612		$	29,142
Add/(deduct):
Interest expense, net	11,111			11,772			10,716			9,898			21,826			21,671
Tax provision	2,571			413			1,542			1,056			4,113			1,469
Depreciation and amortization	8,598			8,388			8,518			8,408			17,115			16,797
EBITDA (3):	$	69,014		$	54,494		$	(4,349	)	$	14,584		$	64,666		$	69,079
Add/(deduct):
Change in unrealized (loss) gain on inventory (1)	(13,549		)	4,236			32,326			364			18,775			4,598
Change in unrealized value on natural gas transportation contracts (2)	(13,199		)	(7,988		)	(123		)	(5,446		)	(13,322		)	(13,434		)
Acquisition related expenses (4)	1			8			1			2			1			9
Other adjustments (5)	159			171			161			174			320			346
Adjusted EBITDA	$	42,426		$	50,921		$	28,016		$	9,678		$	70,440		$	60,598
Other Data:
Ten Year Average Heating Degree Days (6)	2,640			2,657			574			582			3,214			3,239
Heating Degree Days (6)	2,176			2,620			774			539			2,950			3,159
Variance from average heating degree days	(18		)%	(1		)%	35		%	(7		)%	(8		)%	(2		)%
Variance from prior period heating degree days	(17		)%	2		%	44		%	(19		)%	(7		)%	(3		)%

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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 expense.

(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.

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Analysis of Operating Segments

Three Months Ended ~~March 31,~~June 30, 2020 compared to Three Months Ended ~~March 31,~~June 30, 2019



	Three Months Ended March 31,				Increase/(Decrease)					Three Months Ended June 30,					Increase/(Decrease)
	2020		2019		$			%		2020			2019		$			%
	(in thousands, except adjusted unit gross margin)									(in thousands, except adjusted unit gross margin)
Volumes:
Refined products (gallons)	480,486		549,492		(69,006		)	(13	)%	264,332			279,562		(15,230		)	(5	)%
Natural gas (MMBtus)	18,328		19,804		(1,476		)	(7	)%	11,141			12,929		(1,788		)	(14	)%
Materials handling (short tons)	886		922		(36		)	(4	)%	391			523		(132		)	(25	)%
Materials handling (gallons)	78,447		106,223		(27,776		)	(26	)%	148,872			144,687		4,185			3	%
Net Sales:
Refined products	$	841,942	$	1,120,123	$	(278,181	)	(25	)%	$	292,889		$	584,313	$	(291,424	)	(50	)%
Natural gas	95,778		114,167		(18,389		)	(16	)%	47,988			58,108		(10,120		)	(17	)%
Materials handling	15,557		16,481		(924		)	(6	)%	12,974			14,313		(1,339		)	(9	)%
Other operations	6,602		7,537		(935		)	(12	)%	4,363			5,284		(921		)	(17	)%
Total net sales	$	959,879	$	1,258,308	$	(298,429	)	(24	)%	$	358,214		$	662,018	$	(303,804	)	(46	)%
Adjusted Gross Margin:
Refined products	$	35,792	$	44,739	$	(8,947	)	(20	)%	$	52,861		$	27,646	$	25,215		91	%
Natural gas	29,787		32,322		(2,535		)	(8	)%	(2,245		)	4,647		(6,892		)	(148	)%
Materials handling	15,581		16,451		(870		)	(5	)%	12,895			14,334		(1,439		)	(10	)%
Other operations	1,951		1,932		19			1	%	1,673			1,649		24			1	%
Total adjusted gross margin	$	83,111	$	95,444	$	(12,333	)	(13	)%	$	65,184		$	48,276	$	16,908		35	%
Adjusted Unit Gross Margin:
Refined products	$	0.074	$	0.081	$	(0.007	)	(9	)%	$	0.200		$	0.099	$	0.101		102	%
Natural gas	$	1.625	$	1.632	$	(0.007	)	0	%	$	(0.202	)	$	0.359	$	(0.561	)	(156	)%

Refined Products

Refined products net sales decreased ~~$278.2~~$291.4 million, or ~~25%~~50%, compared to the same period last year, due to ~~both~~primarily to lower prices, ~~and volumes.~~with a reduction in volumes also a factor. There was a ~~14% reduction~~47% decline in average sales price, with the lower prices reflecting the general supply surplus in the global oil market led by ongoing high output from both Saudi Arabia and Russia as ~~a result of~~well as reduced demand due to the ~~weaker price environment, in particular during the latter part of the quarter as a result of significant drops in oil prices following the developments~~impact of the COVID-19 pandemic. Although these countries reached an agreement to reduce output in early April, prices remained much lower than last year. Volumes decreased by ~~13%~~5%, primarily from a reduction in distillates, in particular diesel fuel sales to support transportation requirements such as transit agencies and bus companies. Gasoline volumes were higher as new customer activity more than offset lower sales to existing customers, as requirements waned in the lower demand environment. A decline in ~~distillates. In particular, lower heating oil sales due to the extremely mild weather negatively impacted demand and contributed to higher competitive intensity. Heavy~~heavy oil volumes ~~were also lower, again due to~~essentially offset the milder weather as well as the low natural gas price environment. Gasoline volumes increased, with most of the gains occurring prior to mid-March when the impact of the slowdown due to the COVD-19 pandemic intensified. The disruptions due to COVID-19 also led to lower diesel demand, in particular with bus companies and transit agencies.gasoline volume gain.

Refined products adjusted gross margin ~~decreased $8.9~~increased $25.2 million, or ~~20%~~91%, compared to the same period last year. The ~~13% decline in volumes~~majority of this gain was ~~the primary factor leading to this reduction, with the 9% lower adjusted unit gross margin also~~ a notable contributor. Key factors contributing to the lower adjusted unit margin included the heightened competitive intensity due to the lower demand in a well-supplied market and a less attractive near-termresult of an improved market structure to purchase and store ~~inventory.~~oil products, which led to significant mark-to-market gains on inventory and hedge activity (non-GAAP measures). This factor was the key element leading to the higher margins in both the U.S. and Canadian operations. Another positive contributor was enhanced unit margins in discretionary sales, which widened in conjunction with the improved economics of the oil storage alternative. Overall, the unit margins were more than double those obtained last year. Although volumes were lower, the benefit of the improved unit margins was much higher than the impact of the volume decline.

Natural Gas

Natural gas net sales decreased ~~$18.4~~$10.1 million, or ~~16%~~17%, compared to the same period last year due primarily to ~~a combination of a 9% lower average sales price and a 7%~~the 14% reduction in volume. Sales prices were also lower, at 4% less than last year. The decreased volumes were primarily due to the economic slowdown resulting from the COVID-19 pandemic. The lower average sales price reflects the ~~weaker energy price environment compared to last year. The decreased volumes were primarily a result~~ongoing weakness in natural gas prices.

Table of the mild weather, with heating degree days down by 17% compared to last year. The impact of any demand reduction due to COVID-19 disruptions was a lesser factor and notable only beginning about mid-March.Contents

Natural gas adjusted gross margin decreased ~~$2.5~~$6.9 million, or 8%148%, compared to the same period last year, primarily due to a reduction in the ~~lower sales volume.~~adjusted unit gross margin. The ~~average~~negative adjusted unit gross margin ~~was comparable~~reflects a number of market dynamics, including the impact of the COVID-19 economic slowdown leading to near-term competitive pressures and, in conjunction with weaker prices, providing limited supply optimization opportunities. Other factors included unrealized valuation adjustments on forward hedge positions, a higher proportion of shorter-term deals for larger customers given the uncertain market environment, and the typically lower margins during the reduced demand spring period. The 14% lower sales volumes also contributed to the ~~same period last year.~~

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reduced gross margin.

Materials Handling

Materials handling net sales and adjusted gross margin were both ~~$15.6~~$12.9 million, ~~$0.9~~or approximately $1.4 million lower than the same period last year. More than half of this decrease occurred at our ~~U.S.~~Canadian operations, resulting from lower bulk deliveries partly due to timing differences as well as tariff-driven reductions in pulp and paper handling. An increase in asphalt handling partially offset these reductions. Kildair adjusted gross margin also declined compared to the same period last year, primarily due to the expiration of athe crude handling contract at the end of May 2019. This reduction ~~at Kildair~~ was partially offset by increases in ~~Vacuum Gas Oil and Heavy Fuel Oil~~refined products tank rental ~~income~~income. Results in the U.S. operations were also lower, principally due to reductions from ~~two customers.~~the exit of newsprint handling, lower road salt activity during the mild winter, and a decline in handling requirements for building construction material in the COVID-19 environment. Higher windmill component handling activity provided a partial offset to these decreases.

Other Operations

Net sales from other operations decreased $0.9 million, or ~~12%~~17%, due primarily to reduced coal volumes compared to the same period last year. Adjusted gross margin was slightly higher than last year, with better coal adjusted unit gross margins more than offsetting a reduction in the 3rd-party trucking requirements at our Canadian operations and lower boiler service requirements.

Six Months Ended June 30, 2020 compared to Six Months Ended June 30, 2019




	Six Months Ended June 30,				Increase/(Decrease)
	2020		2019		$			%
	(in thousands, except adjusted unit gross margin)
Volumes:
Refined products (gallons)	744,813		829,054		(84,241		)	(10	)%
Natural gas (MMBtus)	29,469		32,733		(3,264		)	(10	)%
Materials handling (short tons)	1,277		1,445		(168		)	(12	)%
Materials handling (gallons)	227,319		250,910		(23,591		)	(9	)%
Net Sales:
Refined products	$	1,134,831	$	1,704,436	$	(569,605	)	(33	)%
Natural gas	143,766		172,275		(28,509		)	(17	)%
Materials handling	28,531		30,794		(2,263		)	(7	)%
Other operations	10,965		12,821		(1,856		)	(14	)%
Total net sales	$	1,318,093	$	1,920,326	$	(602,233	)	(31	)%
Adjusted Gross Margin:
Refined products	$	88,650	$	72,384	$	16,266		22	%
Natural gas	27,542		36,968		(9,426		)	(25	)%
Materials handling	28,476		30,785		(2,309		)	(8	)%
Other operations	3,626		3,581		45			1	%
Total adjusted gross margin	$	148,294	$	143,718	$	4,576		3	%
Adjusted Unit Gross Margin:
Refined products	$	0.119	$	0.087	$	0.032		37	%
Natural gas	$	0.935	$	1.129	$	(0.194	)	(17	)%

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Refined Products

Refined products net sales decreased $569.6 million, or 33%, compared to the same period last year, due to a combination of lower prices and volumes. The 10% decline in volume was primarily due to a reduction in distillates, with heavy oil also a contributor. The lower distillate volumes were due primarily to a combination of less supportive winter weather impacting heating oil demand and a reduction in diesel fuel requirements driven by the COVID-19 slowdown. Heavy oil volumes also declined, again with the milder winter weather and the pandemic-driven economic slowdown key factors. For heavy oil, the milder weather contributed to the limited number of natural gas interruptions, with the economic slowdown leading to lower overall industrial demand as well as reduced ~~coal~~marine bunker requirements. Gasoline volumes ~~and~~increased, with sales ~~prices~~to new customers more than offsetting weaker overall market demand. The 26% lower average sales price reflects the reduced market price environment during the six months ended June 30, 2020 compared to the same period last year.

Refined products adjusted gross margin increased $16.3 million, or 22%, compared to the same period last year due to a 37% higher average adjusted unit gross margin. The gain in adjusted unit gross margin occurred primarily as a result of the improved market structure to purchase, store and hedge oil inventory that ensued in the early part of April in conjunction with the surplus supply and weakened demand environment, with improved unit gross margins on discretionary sales also a factor.

Natural Gas

Natural gas net sales decreased $28.5 million, or 17%, compared to the same period last year, with both reduced volumes and the lower natural gas price environment contributing to the decline. The 10% lower volumes compared to last year are due primarily to a combination of the mild winter weather and the subsequent economic slowdown following the onset of the COVID-19 pandemic.

Natural gas adjusted gross margin decreased by $9.4 million, or 25%, compared to the same period last year, with the 17% lower adjusted unit gross margin the key factor. The decrease in adjusted unit gross margins reflects a reduction compared to the results achieved with the higher cash prices and margin opportunities in the winter period last year. In addition, the weak near-term gross unit margin environment this year following the pandemic-induced slowdown further exacerbated the limited supply optimization opportunities and led to unrealized valuation losses on forward hedge positions. The 10% reduction in volumes also contributed to the gross margin decrease.

Materials Handling

Materials handling net sales and adjusted gross margin both decreased $2.3 million, or approximately 8%, compared to the same period last year. This decline was a result of a reduction in our Canadian operations due to the expiration of the crude handling contract at the end of May 2019. The lack of the crude handling revenue was partially offset by gains from refined products tank rental agreements. At Sprague’s U.S. operations, adjusted gross margin increased modestly, with additional revenue from windmill component handling mostly offset by the exit from newsprint handling and COVID-19 related weakness in the building construction market.

Other Operations

Net sales from other operations decreased by $1.9 million, or 14%, due primarily to reduced coal volumes compared to the same period last year. Adjusted gross margin was modestly higher than last year, with higher coal adjusted gross unit margins more than offsetting a reduction in the 3rd-party trucking requirements at our Canadian operations and lower boiler service requirements.

Operating Costs and Expenses

Three Months Ended ~~March 31,~~June 30, 2020 compared to Three Months Ended ~~March 31,~~June 30, 2019


	Three Months Ended March 31,				Increase/(Decrease)				Three Months Ended June 30,				Increase/(Decrease)
	2020		2019		$			%	2020		2019		$			%
	(in thousands)								(in thousands)
Operating expenses	$	20,812	$	23,789	$	(2,977	)	(13)%	$	18,471	$	21,075	$	(2,604	)	(12)%
Selling, general and administrative	$	20,033	$	20,913	$	(880	)	(4)%	$	18,923	$	17,827	$	1,096		6%
Depreciation and amortization	$	8,598	$	8,388	$	210		3%	$	8,518	$	8,408	$	110		1%
Interest expense, net	$	11,111	$	11,772	$	(661	)	(6)%	$	10,716	$	9,898	$	818		8%

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Operating Expenses. Operating expenses decreased ~~$3.0~~$2.6 million, or ~~13%~~12%, compared to the same period last year, primarily reflecting a decrease of ~~$1.4~~$1.5 million of ~~employee related~~employee-related expenses as well as a $0.5 million decrease in ~~utilities~~stockpile expenses and ~~boiler fuel costs,~~a $0.4 million decrease in ~~insurance related expenses and $0.3 million decrease in repair and maintenance~~Energy Field Services costs.

Selling, General and Administrative Expenses. SG&A expenses ~~decreased $0.9~~increased $1.1 million, or 4%6%, compared to the same period last year driven by ~~a decrease~~an increase of ~~$1.6~~$1.4 million in ~~employee~~incentive compensation expense and a $0.9 million increase in legal and audit expenses, partially offset by a $0.8 million decrease in travel and promotions related to COVID-19.

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

Interest Expense, net. Interest expense, net increased $0.8 million, or 8%, compared to the same period last year primarily due to a non-recurring write-off of certain deferred financing fees related to our May 2020 credit facility refinancing partially offset by decreased net borrowing rates.

Six Months Ended June 30, 2020 compared to Six Months Ended June 30, 2019



	Six Months Ended June 30,				Increase/(Decrease)
	2020		2019		$			%
	(in thousands)
Operating expenses	$	39,283	$	44,864	$	(5,581	)	(12)%
Selling, general and administrative	$	38,956	$	38,739	$	217		1%
Depreciation and amortization	$	17,115	$	16,797	$	318		2%
Interest expense, net	$	21,826	$	21,671	$	155		1%

Operating Expenses. Operating expenses decreased $5.6 million, or 12%, compared to the same period last year, reflecting $2.8 million of decreased employee-related costs, $0.9 million of decreased utilities and boiler fuel expenses, $0.7 million of decreased Energy Field Services expenses and $0.5 million of decreased repair and maintenance expenses.

Selling, General and Administrative Expenses. SG&A expenses increased $0.2 million or 1%, compared to the same period last year. This increase was driven by $2.1 million in higher incentive compensation and $0.8 million of increased legal and audit expenses, partially offset by $1.7 million in employee-related costs attributed to our cost reduction ~~initiatives. partially offset by~~initiatives and a ~~$0.6~~$0.7 million ~~increase~~decrease in ~~incentive compensation expense.~~travel and promotions related to COVID-19.

Depreciation and Amortization. Depreciation and amortization increased ~~$0.2~~$0.3 million or 3%2% as increased depreciation expense was partially offset by decreased amortization expense.

Interest Expense, net. Interest expense, net ~~decreased $0.7~~increased $0.2 million, or 6%1%, compared to the same period last year primarily due to a non-recurring write-off of certain deferred financing fees in the second quarter related to our credit facility refinancing transaction, partially offset by 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 ~~March 31,~~June 30, 2020, we had working capital of ~~$(16.4)~~$(0.1) million.

As of ~~March 31,~~June 30, 2020, the undrawn borrowing capacity under the working capital facilities of our Credit Agreement was ~~$52.6~~$77.1 million and the undrawn borrowing capacity under the acquisition facility was ~~$198.0~~$38.0 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 ~~three~~six months ended ~~March 31,~~June 30, 2020, the amount drawn under the working capital facilities of our Credit Agreement fluctuated from a low of ~~$260.0~~$205.8 million to a high of $452.9 million.

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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 19, 2020, 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 second amended and restated credit agreement (the “Credit Agreement”), which replaced the amended and restated credit agreement, dated December 9, 2014. Upon the effective date, the Credit Agreement was accounted for as a modification of a syndicated loan arrangement with partial extinguishment to the extent of the decrease in the borrowing capacity. The Credit Agreement matures on May 19, 2022. 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”).

Sprague Operating Resources LLC and Kildair, wholly owned subsidiaries of the Partnership, are borrowers under an amended and restated revolving credit agreement (our "Credit Agreement") that matures on ~~April 27, 2021.~~May 19, 2022. Obligations under the Credit Agreement are secured by substantially all of the assets of the Partnership and its subsidiaries.

As of ~~March 31,~~June 30, 2020, 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 ~~$950.0~~$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 ~~$100.0~~$85.0 million, subject to borrowing base limits, to be used for working capital loans and letters of credit;

Subject to certain conditions including the receipt of additional commitments from lenders, the ability to increase the U.S. dollar revolving working capital facility ~~by $250.0 million~~to up to $1.2 billion and the multicurrency revolving working capital facility by ~~$220.0~~$320.0 million, subject to a maximum combined increase in commitments for both facilities of ~~$270.0~~$470.0 million in the aggregate. Additionally, subject to certain conditions, the revolving acquisition facility may be increased ~~by $200.0~~to up to $750.0 million.

Indebtedness under the Credit Agreement bears interest, at the ~~borrowers'~~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)~~costs, and in each case with a floor of 0.50%) for interest periods of one, two, three or six months plus a specified margin or (ii) an alternate rate plus a specified margin.

The specified ~~margin~~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. On or prior to November 19, 2020, the specified margin for (x) the committed U.S. dollar revolving working capital facility will range ~~based upon~~from 1.25% to 1.75% for loans bearing interest at the ~~percentage utilization of this~~Base Rate and from 2.25% to 2.75% for loans bearing interest at the Eurocurrency Rate, (y) the uncommitted U.S. dollar revolving working capital facility will range from 1.00% to 1.50% for loans bearing interest at the ~~alternative~~ Base Rate and ~~from~~ 2.00% to 2.50% for loans bearing interest at the Eurocurrency Rate and ~~for letters of credit issued under~~(z) the ~~U.S. dollar~~multicurrency revolving working capital facility orwill range from

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1.25% to 1.75% for loans bearing interest at the Base Rate and 2.25% to 2.75% for loans bearing interest at the Eurocurrency Rate. After November 19, 2020, the specified margin for (x) the committed U.S. dollar revolving working capital facility will range from 0.75% to 1.25% for loans bearing interest at the Base Rate and from 1.75% to 2.25% for loans bearing interest at the Eurocurrency Rate, (y) the uncommitted U.S. dollar revolving working capital facility will range from 0.50% to 1.00% for loans bearing interest at the Base Rate and 1.50% to 2.00% for loans bearing interest at the Eurocurrency Rate and (z) the multicurrency revolving working capital ~~facility.~~ facility will 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.

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 will range ~~based on the Partnership’s consolidated total leverage ratio,~~ from 1.25% to 2.25% for loans bearing interest at the ~~alternate~~ Base Rate and from 2.25% to 3.25% for loans bearing interest at the Eurocurrency ~~Rate and for letters of credit issued under the acquisition facility.~~ Rate.

In addition, the ~~Partnership~~Borrowers will incur a commitment fee on the unused portion of (x) the ~~facilities~~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 ~~0.375%~~0.35% to 0.50% per annum. Overdue amounts bear interest at the applicable rates described above plus an additional margin of 2%.

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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 ~~Partnership~~Loan Parties would not be in pro forma compliance with ~~its~~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 ~~Partnership~~Loan Parties to maintain: a minimum consolidated EBITDA-to-fixed charge ratio, a minimum consolidated net working capital amount ~~a maximum consolidated total leverage-to-EBITDA ratio~~ and a maximum consolidated ~~senior secured~~total leverage-to-EBITDA ratio. The Credit Agreement also limits the ~~Partnership's~~Loan Parties ability to incur debt, grant liens, make certain investments or acquisitions, enter into affiliate transactions and dispose of ~~assets, and incur additional indebtedness.~~assets. The Partnership was in compliance with the covenants under the Credit Agreement at ~~March 31,~~June 30, 2020.

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.

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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						Capital Expenditures
	Expansion		Maintenance		Total		Expansion		Maintenance		Total
	(in thousands)						(in thousands)
Three Months Ended March 31,
Six Months Ended June 30,
2020	$	702	$	2,310	$	3,012	$	2,287	$	3,099	$	5,386
2019	$	1,069	$	1,124	$	2,193	$	2,624	$	2,800	$	5,424

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

Three Months Ended March 31,
2020 2019
(in thousands)
Net cash provided by (used in) operating activities $ 201,101
$ (2,975 )
Net cash used in investing activities $ (3,001 ) $ (2,171 )
Net cash (used in) provided by financing activities $ (193,807 ) $ 4,040

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	Six Months Ended June 30,
	2020			2019
	(in thousands)
Net cash provided by operating activities	$	177,281		$	137,470
Net cash used in investing activities	$	(5,145	)	$	(5,224	)
Net cash used in financing activities	$	(172,945	)	$	(133,694	)

Operating Activities

Net cash provided by operating activities for the ~~three~~six months ended ~~March 31,~~June 30, 2020 was ~~$201.1~~$177.3 million. Cash inflows for the period were the result of a decrease of ~~$183.3~~$96.8 million in inventories due to a reduction in seasonal inventory requirements, a decrease of ~~$100.3~~$173.8 million in accounts receivable due to a seasonal reduction in sales volume ~~$46.7 million in~~and net income ~~and a decrease in other assets~~ of ~~$34.3~~$21.6 million. These inflows were offset by cash outflows as a result of a reduction of ~~$54.3~~$113.3 million in accounts payable and accrued liabilities primarily relating to the timing of invoice payments for product purchases and ~~$118.2~~$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~~period.

Net cash ~~used in~~provided by operating activities for the ~~three~~six months ended ~~March 31,~~June 30, 2019 was ~~$3.0~~$137.5 million. Cash inflows for the period were the result of a decrease of ~~$49.8~~$133.0 million in inventories due to a reduction in inventory requirements, ~~$33.9~~a decrease of $108.5 million in accounts receivable due to a seasonal reduction in sales volume, $29.1 million in net income and ~~$32.8~~$24.7 million representing the net impact in our derivative instruments as a result of contract activity and changes in commodity prices during the ~~period and seasonal changes.~~period. These inflows were offset by cash outflows as a result of a reduction of ~~$109.5~~$161.2 million in accounts payable and accrued liabilities primarily relating to the timing of invoice payments for product purchases.

Investing Activities

Net cash used in investing activities for the ~~three~~six months ended ~~March 31,~~June 30, 2020 was ~~$3.0~~$5.1 million, and primarily resulted from ~~$0.7~~$2.3 million related to expansion capital expenditures and ~~$2.3~~$3.1 million related to maintenance capital expenditure projects across our terminal system.

Net cash used in investing activities for the ~~three~~six months ended ~~March 31,~~June 30, 2019 was ~~$2.2~~$5.2 million, ~~of which $1.1~~and primarily resulted from $2.6 million related to expansion capital expenditures and ~~$1.1~~$2.8 million related to maintenance capital expenditure projects across our terminal system.

Financing Activities

Net cash used in financing activities for the ~~three~~six months ended ~~March 31,~~June 30, 2020 was ~~$193.8~~$172.9 million, and primarily resulted from ~~$176.7~~$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 ~~$15.2~~$32.6 million.

Net cash ~~provided by~~used in financing activities for the ~~three~~six months ended ~~March 31,~~June 30, 2019 was ~~$4.0~~$133.7 million, and primarily resulted from ~~$22.5~~$97.0 million of payments under our Credit Agreement due to reduced financing requirements from accounts receivable levels, ~~and~~ the reduction of inventory levels and distributions of ~~$17.2~~$34.5 million.

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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 ~~three~~six months ended ~~March 31,~~June 30, 2020 and 2019.

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 2019 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 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 and (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 March 31,					Three Months Ended June 30,						Six Months Ended June 30,
	(in thousands)					(in thousands)
	2020		2019			2020			2019			2020		2019
Refined products contracts	$	66,205	$	(16,383	)	$	(8,869	)	$	(5,513	)	$	57,336	$	(21,896	)
Natural gas contracts	36,013		13,379			3,332			10,688			39,345		24,067
Total	$	102,218	$	(3,004	)	$	(5,537	)	$	5,175		$	96,681	$	2,171

Substantially all of our commodity derivative contracts outstanding as of ~~March 31,~~June 30, 2020 will settle prior to ~~September 30,~~December 31, 2021.

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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 ~~March 31,~~June 30, 2020 were as follows (in thousands):


Beginning	Ending	Notional Amount		Ending	Notional Amount
January 2020	January 2021	$	300,000	January 2021	$	300,000
April 2020				April 2021	$	25,000
January 2021	January 2022	$	300,000	January 2022	$	300,000
April 2021				April 2022	$	25,000
January 2022	January 2023	$	250,000	January 2023	$	250,000
April 2022				April 2023	$	25,000

During the two year period ended ~~March 31,~~June 30, 2020 we hedged approximately 46% 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 ~~March 31,~~June 30, 2020, we estimate that if short-term interest rates increased or decreased 100 basis points, our interest expense would have increased approximately $3.5 million and decreased approximately $3.5 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 ~~March 31,~~June 30, 2020:


	As of March 31, 2020								As of June 30, 2020
	Fair Value Measurement		Active Markets Level 1		Observable Inputs Level 2		Unobservable Inputs Level 3		Fair Value Measurement		Active Markets Level 1		Observable Inputs Level 2		Unobservable Inputs Level 3
	(in thousands)								(in thousands)
Derivative assets:
Commodity exchange contracts	$	15	$	15	$	—	$	—
Commodity fixed forwards	130,918		—		130,918		—		$	91,264	$	—	$	91,264	$	—
Futures, swaps and options	248,031		248,012		19		—		130,466		130,461		5		—
Commodity derivatives	378,964		248,027		130,937		—		221,730		130,461		91,269		—
Currency swaps	3		—		3		—
Total derivative assets	$	378,967	$	248,027	$	130,940	$	—	$	221,730	$	130,461	$	91,269	$	—
Derivative liabilities:
Commodity fixed forwards	$	7,507	$	—	$	7,507	$	—	$	15,949	$	—	$	15,949	$	—
Futures, swaps and options	237,962		237,916		46		—		160,823		160,821		2		—
Commodity derivatives	245,469		237,916		7,553		—		176,772		160,821		15,951		—
Interest rate swaps	16,128		—		16,128		—		15,943		—		15,943		—
Total derivative liabilities	$	261,597	$	237,916	$	23,681	$	—	$	192,721	$	160,821	$	31,900	$	—

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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 ~~March 31,~~June 30, 2020, 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 ~~March 31,~~June 30, 2020.

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 ~~March 31,~~June 30, 2020 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 as well as the excerpt below, you should carefully consider the factors discussed in Part I, Item 1A “Risk Factors” included in our 2019 Annual Report, which could materially affect our business, financial condition or future results.

The novel coronavirus outbreak (COVID-19) could adversely impact our business, financial condition and results of operations.

The global outbreak of 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. We have taken measures to protect the health and safety of our employees, work with our customers to minimize potential disruptions and support our community in addressing the challenges posed by this global pandemic. The extent of the impact of the COVID-19 pandemic on our operational and financial performance will depend on future developments, including the duration and spread of the pandemic and related actions taken by the U.S. government, state and local government officials, and international governments to prevent disease spread, all of which are uncertain and cannot be predicted. However, we do anticipate a decline in volumes of natural gas and petroleum products sold in the next several months until the pandemic response moves through Phase I, II and Phase III along with a corresponding reduction in revenue, gross margin and EBITDA. We continue to work with our customers, employees, suppliers and communities to address the impacts of COVID-19. We continue to assess possible implications to our business, supply chain and customers, and to take actions in an effort to mitigate adverse consequences.



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

On January 23, 2020, we entered into a letter agreement with the Sponsor and Sprague Holdings providing that Sprague Holdings would receive common units, representing limited partner interests in the Partnership, in lieuPurchases of cash, in respect of the incentive distribution rights payable in connection with the distribution for the fourth quarter of 2019. The number of such common units that were issued to Sprague Holdings was computed based upon the lesser of an incentive distribution rights cash payment of $2,055,252 dividedEquity Securities by the market price on close of business on January 23, 2020 or the number of units based on the 10-day volume weighted average price ending December 31, 2019. Accordingly, on February 10, 2020, we issued 121,150 common units to Sprague Holdings in lieu of an aggregate cash payment of $2,055,252 that would have been payable on the incentive distribution rights for such quarter. The transaction was undertaken in reliance upon the exemption from the registration requirements of the Securities Act of 1933, as amended, contained in Section 4(2) thereof.Issuer and Affiliated Purchasers



	Total number of common units purchased(2)	Average price paid per common unit		Total number of common units purchased as part of publicly announced plans or programs	Maximum number of common units that may yet be purchased under the plans or programs
April 1, 2020-April 30, 2020	—	$	—	—	N/A
May 1, 2020-May 31, 2020	—	$	—	—	N/A
June 1, 2020-June 30, 2020	723,738	$	13.85	—	N/A

(1)

On June 5, 2020, Sprague Holdings purchased 723,738 common units of the Partnership at a price of $13.85 per common unit (or $10.0 million in the aggregate) in a privately negotiated transaction. The source of funds for the purchase was cash on hand. The transaction was undertaken in reliance upon the exemption from the registration requirements of the Securities Act of 1933, as amended, contained in Section 4(2) thereof.



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. 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)).

3.4		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)).

3.5		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)).

3.6		Amended and Restated Limited Liability Company Agreement of Sprague Resources GP LLC (incorporated by reference to Exhibit 3.2 of Sprague Resources LP’s Current Report on Form 8-K filed November 5, 2013 (File No. 001-36137)).

3.7		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, and Amendment No. 2, effective October 25, 2019 (incorporated by reference to Exhibit 3.7 of Sprague Resources LP’s Annual Report on Form 10-K for the year ended December 31, 2019, filed March 5, 2020 (File No. 001-36137)).

10.1		Second Amended and Restated Credit Agreement, dated as of 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 21, 2020 (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.

101.INS*		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*		XBRL Taxonomy Extension Schema Document

101.CAL*		XBRL Taxonomy Extension Calculation

Table of Contents

101.DEF*

101.DEF		XBRL Taxonomy Extension Definition

101.LAB*		XBRL Taxonomy Extension Label Linkbase

101.PRE*		XBRL Taxonomy Extension Presentation

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

*		Filed herewith.

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**		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: ~~May 7,~~August 6, 2020		/s/ David C. Long
		David C. Long Chief Financial Officer (on behalf of the registrant, and in his capacity as Principal Financial Officer)

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