Sprague Resources (SRLP) 10-Q 2019 Q1 Quarterly report

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, 2019

or

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

For the transition period from to

Commission file number: 001-36137

Sprague Resources LP

(Exact name of registrant as specified in its charter)

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

185 International Drive

Portsmouth, New Hampshire 03801

(Address of principal executive offices)

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

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

Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common Units Representing	SRLP	New York Stock Exchange
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  x    No  o

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulations 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  x    No  o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, 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	o	Accelerated filer	x
Non-accelerated filer	o	Smaller reporting company	o
Emerging growth company	o

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.   o

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

The registrant had 22,733,977 common units outstanding as of May 6, 2019.

Table of Contents

		Page
PART I—FINANCIAL INFORMATION
Item 1.	Financial Statements:
	Condensed Consolidated Balance Sheets as of March 31, 2019 (unaudited) and December 31, 2018	1
	Unaudited Condensed Consolidated Income Statements for the three months ended March 31, 2019 and March 31, 2018	2
	Unaudited Condensed Consolidated Statements of Comprehensive Income for the three months ended March 31, 2019 and March 31, 2018	3
	Unaudited Condensed Consolidated Statements of Unitholders’ Equity (Deficit) for the three months ended March 31, 2019 and March 31, 2018	4
	Unaudited Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2019 and March 31, 2018	5
	Notes to Unaudited Condensed Consolidated Financial Statements	6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	22
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	36
Item 4.	Controls and Procedures	39
PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	40
Item 1A.	Risk Factors	40
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	40
Item 3.	Defaults Upon Senior Securities	40
Item 4.	Mine Safety Disclosures	40
Item 5.	Other Information	40
Item 6.	Exhibits	41
Signatures		42

Part I – FINANCIAL INFORMATION

Item 1 — Condensed Consolidated Financial Statements

Sprague Resources LP

Condensed Consolidated Balance Sheets

(in thousands except unit amounts)

	March 31, 2019			December 31, 2018
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	6,457		$	7,530
Accounts receivable, net	274,813			269,908
Inventories	209,817			259,568
Fair value of derivative assets	57,436			153,438
Other current assets	23,803			8,888
Total current assets	572,326			699,332
Fair value of derivative assets, long-term	20,545			12,344
Property, plant and equipment, net	347,062			349,846
Intangibles, net	57,308			59,987
Other assets, net	25,905			8,694
Goodwill	115,037			115,037
Total assets	$	1,138,183		$	1,245,240
Liabilities and unitholders’ equity
Current liabilities:
Accounts payable	$	113,865		$	197,995
Accrued liabilities	46,348			65,959
Fair value of derivative liabilities	43,944			90,151
Due to General Partner	7,147			7,688
Current portion of working capital facilities	131,419			154,318
Current portion of other obligations	7,214			7,044
Total current liabilities	349,937			523,155
Commitments and contingencies
Working capital facilities, less current portion	204,115			130,680
Acquisition facility	348,100			376,100
Fair value of derivative liabilities, long-term	6,343			12,015
Other obligations, less current portion	45,529			46,455
Operating lease liabilities, less current portion	12,780			—
Due to General Partner	2,205			2,093
Deferred income taxes	18,764			17,766
Total liabilities	987,773			1,108,264
Unitholders’ equity:
Common unitholders - public (10,627,629 units issued and outstanding)	204,391			196,680
Common unitholders - affiliated (12,106,348 units issued and outstanding)	(39,399		)	(48,182		)
Accumulated other comprehensive loss, net of tax	(14,582		)	(11,522		)
Total unitholders’ equity	150,410			136,976
Total liabilities and unitholders’ equity	$	1,138,183		$	1,245,240

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

1

Sprague Resources LP

Unaudited Condensed Consolidated Income Statements

(in thousands except unit and per unit amounts)

	Three Months Ended March 31,
	2019			2018
Net sales	$	1,258,308		$	1,331,148
Cost of products sold (exclusive of depreciation and amortization)	1,159,112			1,183,982
Operating expenses	23,789			23,209
Selling, general and administrative	20,913			27,864
Depreciation and amortization	8,388			8,425
Total operating costs and expenses	1,212,202			1,243,480
Operating income	46,106			87,668
Interest income	187			112
Interest expense	(11,959		)	(9,884		)
Income before income taxes	34,334			77,896
Income tax provision	(413		)	(2,975		)
Net income	33,921			74,921
Incentive distributions declared	(2,055		)	(1,714		)
Limited partners’ interest in net income	$	31,866		$	73,207
Net income per limited partner unit:
Common - basic	$	1.40		$	3.22
Common - diluted	$	1.40		$	3.21
Units used to compute net income per limited partner unit:
Common - basic	22,733,977			22,725,346
Common - diluted	22,739,609			22,786,889
Distribution declared per unit	$	0.6675		$	0.6525

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

2

Sprague Resources LP

Unaudited Condensed Consolidated Statements of Comprehensive Income

(in thousands)

	Three Months Ended March 31,
	2019			2018
Net income	$	33,921		$	74,921
Other comprehensive (loss) income, net of tax:
Unrealized (loss) gain on interest rate swaps
Net (loss) gain arising in the period	(2,944		)	1,941
Reclassification adjustment related to (loss) gain realized in income	(202		)	(280		)
Net change in unrealized (loss) gain on interest rate swaps	(3,146		)	1,661
Tax effect	25			(13		)
	(3,121		)	1,648
Foreign currency translation adjustment	61			(69		)
Other comprehensive (loss) income	(3,060		)	1,579
Comprehensive income	$	30,861		$	76,500

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

3

Sprague Resources LP

Unaudited Condensed Consolidated Statements of Unitholders’ Equity (Deficit)

(in thousands)

	Common- Public			Common- Sprague Holdings			Incentive Distribution Rights			Accumulated Other Comprehensive Loss			Total
Balance at December 31, 2017	$	193,977		$	(53,273	)	$	—		$	(8,870	)	$	131,834
Net income	34,367			39,181			1,373			—			74,921
Other comprehensive income	—			—			—			1,579			1,579
Unit-based compensation	392			446			—			—			838
Distributions paid	(8,531		)	(7,718		)	(1,373		)	—			(17,622		)
Units withheld for employee tax obligations	(1,172		)	(1,336		)	—			—			(2,508		)
Balance at March 31, 2018	$	219,033		$	(22,700	)	$	—		$	(7,291	)	$	189,042
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	(7,094		)	(8,081		)	(2,055		)	—			(17,230		)
Balance at March 31, 2019	$	204,391		$	(39,399	)	$	—		$	(14,582	)	$	150,410

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

4

Sprague Resources LP

Unaudited Condensed Consolidated Statements of Cash Flows

(in thousands)

	Three Months Ended March 31,
	2019			2018
Cash flows from operating activities
Net income	$	33,921		$	74,921
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization (includes amortization of deferred debt issuance costs)	9,286			9,307
Loss (gain) on sale of assets	(5		)	19
Changes in fair value of contingent consideration	147			171
Provision for doubtful accounts	78			488
Non-cash unit-based compensation	(197		)	838
Other	24			23
Deferred income taxes	1,024			607
Changes in assets and liabilities:
Accounts receivable	(4,947		)	34,666
Inventories	49,751			101,234
Other assets	(14,868		)	12,503
Fair value of commodity derivative instruments	32,777			(60,820		)
Due to General Partner and affiliates	(429		)	(559		)
Accounts payable, accrued liabilities and other	(109,537		)	(116,663		)
Net cash (used in) provided by operating activities	(2,975		)	56,735
Cash flows from investing activities
Purchases of property, plant and equipment	(2,193		)	(3,681		)
Proceeds from sale of assets	22			29
Net cash used in investing activities	(2,171		)	(3,652		)
Cash flows from financing activities
Net borrowings (payments) under credit agreements	22,482			(33,021		)
Payments on finance/capital leases, term debt, and other obligations	(1,212		)	(1,033		)
Debt issue costs	—			(102		)
Distributions to unitholders	(17,230		)	(17,622		)
Repurchased units withheld for employee tax obligations	—			(2,508		)
Net cash provided by (used in) financing activities	4,040			(54,286		)
Effect of exchange rate changes on cash balances held in foreign currencies	33			(3		)
Net change in cash and cash equivalents	(1,073		)	(1,206		)
Cash and cash equivalents, beginning of period	7,530			6,815
Cash and cash equivalents, end of period	$	6,457		$	5,609
Supplemental disclosure of cash flow information
Cash paid for interest	$	10,803		$	9,044
Cash paid for taxes	$	2,901		$	1,639
Assets acquired under finance/capital lease obligations	$	702		$	712

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

5

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 “Axel Johnson” or the “Parent” 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; references to the “General Partner” refer to Sprague Resources GP LLC.

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 business 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, sells and distributes natural gas to commercial and industrial customers. The Partnership purchases the natural gas it sells from natural gas producers and trading companies.

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

• The other operations segment primarily includes the purchase 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, 2019, the Parent, through its ownership of Sprague Holdings, owned 12,106,348 common units representing 53% 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, 2018 as filed with the SEC on March 14, 2019 (the “2018 Annual Report”).

6

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, 2019 and December 31, 2018, the consolidated results of operations for the three months ended March 31, 2019 and 2018, and the consolidated cash flows for the three months ended March 31, 2019 and 2018. 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.

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 2018 Annual Report and are the same as are used in preparing these unaudited interim Condensed Consolidated Financial Statements except for the adoption of ASU 2016-02, Leases (Topic 842) which the Partnership adopted as of January 1, 2019.The adoption of Topic 842 is discussed further in Recent Accounting Pronouncements below as well as in Note 3 "Leases".

Recent Accounting Pronouncements

In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-02, Leases (Topic 842), which, among other things, requires lessees to recognize an obligation to make lease payments arising from a lease, measured on a discounted basis, and a right-of-use asset, which is an asset that represents the lessee's right to use, or control the use of, a specified asset for the lease term. Expenses are recognized in the consolidated income statements in a manner similar to current accounting guidance. The Partnership made an accounting policy election to not recognize an asset and liability for leases with a term of twelve months or less. This ASU is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. The Partnership adopted this new accounting standard using a modified retrospective approach, which applies the provisions of the new guidance as of January 1, 2019 without adjusting the comparative periods presented. See Note 3 "Leases" for further information.

In June 2016, the FASB issued ASU 2016-13, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, which amends the impairment model by requiring 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. The Partnership is currently evaluating the impact of the new standard on its 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. Early adoption is permitted for any impairment tests performed after January 1, 2017.

In July 2017, the FASB issued ASU 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities. The objective of the guidance is to improve the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements. This ASU is effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. The adoption of this new guidance did not have a material impact to the Partnership's consolidated financial statements.

7

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 and exchange 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, sells and distributes natural gas to commercial and industrial customers. The Partnership purchases the natural gas it sells from natural gas producers and trading companies. 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 as 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 purchase and distribution of coal and certain commercial trucking activities. Revenue from other operations is recognized when the product is delivered or the services are rendered.

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

	Three Months Ended March 31,
	2019		2018
Net sales:
Refined products
Distillates	$	964,017	$	981,691
Gasoline	59,341		76,357
Heavy fuel oil and asphalt	96,765		122,812
Total refined products	$	1,120,123	$	1,180,860
Natural gas	114,167		129,927
Materials handling	16,481		13,148
Other operations	7,537		7,213
Net sales	$	1,258,308	$	1,331,148
Net sales by Country:
United States	$	1,202,691	$	1,265,542
Canada	55,617		65,606
Net sales	$	1,258,308	$	1,331,148

8

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 $6.3 million and $9.8 million as of March 31, 2019 and December 31, 2018, respectively. A substantial portion of the contract liabilities as of December 31, 2018 remains outstanding as of March 31, 2019 as they are primarily deposits. The Partnership does not have any material contract assets as of March 31, 2019 or December 31, 2018.

3. Leases

The Partnership adopted the new lease standard using the required modified retrospective approach, effective January 1, 2019. The standard establishes a right-of-use (ROU) model that requires a lessee to recognize a ROU asset and lease liability on the balance sheet for all leases with a term longer than 12 months.

The Partnership chose to apply the transition provisions as of the period of adoption.  Therefore, prior period financial information has not been adjusted and continues to be reflected in accordance with the Partnership’s historical accounting policy. The Partnership elected the package of practical expedients permitted under the transition guidance within the new standard, which, among other things, allowed the Partnership to carry forward the historical lease classification. In addition, the Partnership elected the practical expedient not to apply the recognition requirements in the lease standard to short-term leases (a lease that at commencement date has a lease term of 12 months or less and does not contain a purchase option that it is reasonably certain to exercise) and the practical expedient that permits lessees to make an accounting policy election (by class of underlying asset) to account for each separate lease component of a contract and its associated non-lease components as a single lease component. The adoption of the new standard resulted in the recognition of ROU assets and lease liabilities for operating leases of approximately $19.7 million and $20.0 million, respectively. In addition, capital lease assets and liabilities are now classified as finance lease ROU assets and liabilities. There was no impact on the Partnership’s condensed consolidated statements of unitholders’ equity, condensed consolidated income statements or condensed consolidated statement of cash flows.

The Partnership determines if an arrangement is a lease at inception. The Partnership's ROU assets are included in property, plant and equipment, net and noncurrent other assets for finance leases and operating leases, respectively. Lease liabilities are included in current and noncurrent other obligations in the condensed consolidated balance sheets. Operating lease expense is included in operating expenses and cost of products sold while amortization expense associated with ROU assets for finance leases is included in depreciation and amortization expense.

ROU assets represent the Partnership’s right to use an underlying asset for the lease term and lease liabilities represent the Partnership’s obligations to make lease payments arising from the lease.  ROU assets and liabilities are recognized at commencement date based on the present value of lease payments over the lease term.  The Partnership uses its incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments.  The Partnership’s lease terms may include options to extend lease terms ranging from 1 to 10 years while others include options to terminate at the Partnership’s discretion.

The Partnership’s operating and finance leases are primarily for time charters, facilities, railcars and equipment.  The terms and conditions for these leases vary by the type of underlying asset. For the three months ended March 31, 2019, total operating lease expense was $7.6 million of which $5.4 million was related to short-term leases. For the three months ended March 31, 2019, total finance lease expense was $0.6 million.

9

Operating leases as of March 31, 2019 are as follows:

	Operating			Financing
ROU Assets:
Other Assets, Net	$	18,130		$	—
Property, Plant and Equipment, Net	—			6,219
Total ROU Assets	$	18,130		$	6,219
Lease Liabilities:
Accrued Liabilities	$	5,693		$	—
Current Portion of Other Obligation	—			1,628
Other Obligations, Less Current Portion	—			4,778
Operating Lease Liabilities, Less Current Portion	12,780			—
Total Lease Liabilities	$	18,473		$	6,406
Weighted Average Remaining Lease Term (Years)	4			4
Weighted Average Discount Rate	6.45		%	4.86		%

Supplemental cash flow information related to operating leases as of March 31, 2019 are as follows:

	March 31, 2019
Cash paid for operating leases	$	2,233
ROU assets obtained in exchange for lease obligations	$	424

Maturities of operating and finance lease liabilities as of March 31, 2019 are as follows:

	Operating			Financing
Remaining 2019	$	3,535		$	1,435
2020	5,886			1,867
2021	5,959			1,612
2022	3,029			1,428
2023	685			736
Thereafter	1,232			3
Total Lease Payments	20,326			7,081
Less: Interest	(1,853		)	(675		)
Total	$	18,473		$	6,406

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 contacts 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, 2019, income related to the operating leases with the Partnership as the lessor, as described above, totaled $11.0 million.

10

The undiscounted cash flows to be received on an annual basis from operating leases as of March 31, 2019 are as follows:

	March 31, 2019
Remaining 2019	$	23,013
2020	22,613
2021	17,921
2022	14,440
2023	9,970
Thereafter	52,931
Total Lease Receipts	$	140,888

4. Accumulated Other Comprehensive Loss, Net of Tax

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

	March 31, 2019			December 31, 2018
Fair value of interest rate swaps, net of tax	$	(2,945	)	$	176
Cumulative foreign currency translation adjustment	(11,637		)	(11,698		)
Accumulated other comprehensive loss, net of tax	$	(14,582	)	$	(11,522	)

5. Inventories

	March 31, 2019		December 31, 2018
Petroleum and related products	$	204,821	$	253,385
Coal	4,535		2,566
Natural gas	461		3,617
Inventories	$	209,817	$	259,568

6. Credit Agreement

	March 31, 2019			December 31, 2018
Working capital facilities	$	335,534		$	284,998
Acquisition facility	348,100			376,100
Total credit agreement	683,634			661,098
Less: current portion of working capital facilities	(131,419		)	(154,318		)
Long-term portion	$	552,215		$	506,780

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

As of March 31, 2019, the revolving credit facilities under the Credit Agreement contained, among other items, the following:

• A U.S. dollar revolving working capital facility of up to $950.0 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 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 million, subject to 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, 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 and the multicurrency revolving working capital

11

facility by $220.0 million, subject to a maximum combined increase for both facilities of $270.0 million in the aggregate. Additionally, subject to certain conditions, the revolving acquisition facility may be increased by $200.0 million.

Indebtedness under the Credit Agreement bears interest, at the borrowers’ option, at a rate per annum equal to either (i) the Eurocurrency Rate (which is the LIBOR Rate for loans denominated in U.S. dollars and CDOR for loans denominated in Canadian dollars, in each case adjusted for certain regulatory costs) 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%.

The working capital facilities are subject to borrowing base reporting and as of March 31, 2019 and December 31, 2018, had a borrowing base of $473.3 million and $512.4 million, respectively. As of March 31, 2019 and December 31, 2018, outstanding letters of credit were $61.4 million and $65.5 million, respectively. As of March 31, 2019, excess availability under the working capital facilities was $76.4 million and excess availability under the acquisition facilities was $201.9 million.

The weighted average interest rate was 5.4% and 5.3% at March 31, 2019 and December 31, 2018, respectively. No amounts are due under the Credit Agreement until the maturity date, however, the current portion of the Credit Agreement at March 31, 2019 and December 31, 2018 represents the amounts of the working capital facility intended to be repaid during the following twelve month period.

The Credit Agreement contains certain restrictions and covenants among which include a minimum level of net working capital, fixed charge coverage and debt leverage ratios and limitations on the incurrence of indebtedness. The Credit Agreement limits the Partnership’s ability to make distributions in the event of a default as defined in the Credit Agreement. As of March 31, 2019, the Partnership was in compliance with these covenants.

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 $28.1 million and $35.0 million for the three months ended March 31, 2019 and 2018, respectively. Through the General Partner, the Partnership also participates in the Parent’s pension and other post-retirement benefits. At March 31, 2019 and December 31, 2018, total amounts due to the General Partner with respect to these benefits and overhead costs were $9.4 million and $9.8 million, respectively.

8. Segment Reporting

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

12

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 three 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 operating segment.

The Partnership's materials handling segment offloads, stores, and/or 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 operating segments.

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

The Partnership evaluates segment performance based on adjusted gross margin, a non-GAAP measure, which is net sales less cost of products sold (exclusive of depreciation and amortization) increased by unrealized hedging losses and decreased by unrealized hedging gains, in each case with respect to refined products and natural gas inventory, prepaid forward contracts 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 months ended March 31, 2019 and 2018, respectively. The Partnership’s foreign sales, primarily sales of refined products and natural gas to its customers in Canada, were $55.6 million and $65.6 million for the three months ended March 31, 2019 and 2018, respectively.

13

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

	Three Months Ended March 31,
	2019			2018
Net sales:
Refined products	$	1,120,123		$	1,180,860
Natural gas	114,167			129,927
Materials handling	16,481			13,148
Other operations	7,537			7,213
Net sales	$	1,258,308		$	1,331,148
Adjusted gross margin (1):
Refined products	$	44,739		$	56,335
Natural gas	32,322			37,948
Materials handling	16,451			13,148
Other operations	1,932			2,106
Adjusted gross margin	95,444			109,537
Reconciliation to operating income (2):
Add/(deduct):
Change in unrealized gain on inventory (3)	(4,236		)	23,561
Change in unrealized value on natural gas transportation contracts (4)	7,988			14,068
Operating costs and expenses not allocated to operating segments:
Operating expenses	(23,789		)	(23,209		)
Selling, general and administrative	(20,913		)	(27,864		)
Depreciation and amortization	(8,388		)	(8,425		)
Operating income	46,106			87,668
Interest income	187			112
Interest expense	(11,959		)	(9,884		)
Income tax provision	(413		)	(2,975		)
Net income	$	33,921		$	74,921

(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, prepaid forward contracts and natural gas transportation contracts, which are not marked to market for the purpose of recording unrealized gains or losses in net income. These adjustments align the unrealized hedging gains and losses to the period in which the revenue from the sale of inventory, prepaid fixed forwards and the utilization of transportation contracts relating to those hedges is realized in net income. Adjusted gross margin has no impact on reported volumes or net sales.

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

(3) Inventory is valued at the lower of cost or net realizable value. The adjustment related to 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 gains (losses).

14

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 activities. There are no significant fixed assets attributable to the natural gas reportable segment.

As of March 31, 2019, goodwill recorded for the refined products, natural gas, materials handling and other operations segments amounted to $71.4 million, $35.5 million, $6.9 million and $1.2 million, respectively.

9. Financial Instruments and Off-Balance Sheet Risk

As of March 31, 2019 and December 31, 2018, 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, 2019 and December 31, 2018, 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, 2019 and December 31, 2018, 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, 2019, 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.

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

	As of March 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	$	45,913	$	14	$	45,899	$	—
Futures, swaps and options	30,273		30,223		50		—
Commodity derivatives	76,186		30,237		45,949		—
Interest rate swaps	1,795		—		1,795		—
Total derivative assets	$	77,981	$	30,237	$	47,744	$	—
Derivative liabilities:
Commodity fixed forwards	$	12,306	$	—	$	12,306	$	—
Futures, swaps and options	33,215		33,211		4		—
Commodity derivatives	45,521		33,211		12,310		—
Interest rate swaps	4,762		—		4,762		—
Currency swaps	4		—		4		—
Total derivative liabilities	$	50,287	$	33,211	$	17,076	$	—
Contingent consideration	$	8,549	$	—	$	—	$	8,549

15

	As of December 31, 2018
	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	$	42,893	$	—	$	42,893	$	—
Futures, swaps and options	120,258		120,231		27		—
Commodity derivatives	163,151		120,231		42,920		—
Interest rate swaps	2,629		—		2,629		—
Currency swaps	2		—		2		—
Total derivative assets	$	165,782	$	120,231	$	45,551	$	—
Derivative liabilities:
Commodity fixed forwards	$	21,036	$	—	$	21,036	$	—
Futures, swaps and options	78,678		78,674		4		—
Commodity derivatives	99,714		78,674		21,040		—
Interest rate swaps	2,452		—		2,452		—
Total derivative liabilities	$	102,166	$	78,674	$	23,492	$	—
Contingent consideration	$	8,402	$	—	$	—	$	8,402

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 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, 2019 will settle prior to March 31, 2020.

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

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

16

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 liability.

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, 2019 and December 31, 2018.

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 $51.3 million at March 31, 2019. Information related to these offsetting arrangements is set forth below:

	As of March 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	$	76,186		$	(26,640	)	$	(2,349	)	$	47,197
Interest rate swap derivative assets	1,795			—			—			1,795
Fair value of derivative assets	$	77,981		$	(26,640	)	$	(2,349	)	$	48,992
Commodity derivative liabilities	$	(45,521	)	$	26,640		$	9,671		$	(9,210	)
Interest rate swap derivative liabilities	(4,762		)	—			—			(4,762		)
Currency swaps	(4		)	—			—			(4		)
Fair value of derivative liabilities	$	(50,287	)	$	26,640		$	9,671		$	(13,976	)

17

	As of December 31, 2018
				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	$	163,151		$	(82,837	)	$	(28,529	)	$	51,785
Interest rate swap derivative assets	2,629			—			—			2,629
Currency swaps	2			—			—			2
Fair value of derivative assets	$	165,782		$	(82,837	)	$	(28,529	)	$	54,416
Commodity derivative liabilities	$	(99,714	)	$	82,837		$	20		$	(16,857	)
Interest rate swap derivative liabilities	(2,452		)	—			—			(2,452		)
Fair value of derivative liabilities	$	(102,166	)	$	82,837		$	20		$	(19,309	)

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 March 31,
	2019			2018
Refined products contracts	$	(16,383	)	$	10,203
Natural gas contracts	13,379			872
Total	$	(3,004	)	$	11,075

There were no discretionary trading activities for the three months ended March 31, 2019 and 2018. The following table presents gross volume of commodity derivative instruments outstanding for the periods indicated:

	As of March 31, 2019				As of December 31, 2018
	Refined Products (Barrels)		Natural Gas (MMBTUs)		Refined Products (Barrels)		Natural Gas (MMBTUs)
Long contracts	6,836		133,719		8,796		132,030
Short contracts	(8,904	)	(71,573	)	(12,379	)	(72,223	)

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's interest rate swap agreements outstanding as of March 31, 2019 were as follows:

Beginning	Ending	Notional Amount
January 2019	January 2020	$	300,000
January 2020	January 2021	$	300,000
January 2021	January 2022	$	300,000
January 2022	January 2023	$	250,000

There was no material ineffectiveness determined for the cash flow hedges for the three months ended March 31, 2019 and 2018.

18

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, 2019, the amount of unrealized gains, net of tax, expected to be reclassified to earnings during the following twelve-month period was $0.4 million.

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) and during fiscal 2019 are as follows:

Contingent consideration - December 31, 2018	$	8,402
Change in estimated fair value	147
Contingent consideration - March 31, 2019	$	8,549

10. Commitments and Contingencies

Legal, Environmental and Other Proceedings

The Partnership is subject to a tax on sales made in Quebec on 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 $4.3 million of tax, including interest and penalties, for the period of 2007 to 2017. During September 2018, the Partnership received an assessment of $8.4 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.

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

19

fair value of the award and is recognized over the requisite service period using the straight-line method. The number of units that the Partnership estimates are probable to vest could change over the vesting period. Any such change in estimate is recognized as a cumulative adjustment calculated as if the new estimate had been in effect from the grant date.

The Partnership's long-term incentive phantom unit awards include tandem distribution equivalent rights ("DERs") which entitle the participant to a cash payment upon vesting that is equal to any cash distribution paid on a common unit between the grant date and the date the phantom units were settled.

The following table presents a summary of the Partnership’s phantom unit awards subject to vesting during the three months ended March 31, 2019 :

	2019 Awards					2018 Awards					2017 Awards
	Units		Weighted Average Grant Date Fair Value (per unit)			Units		Weighted Average Grant Date Fair Value (per unit)			Units		Weighted Average Grant Date Fair Value (per unit)
Nonvested at December 31, 2018	—		$	—		123,186		$	23.30		119,996		$	26.96
Granted	180,638		15.04			—		—			—		—
Forfeited	(2,000	)	(15.04		)	(3,954	)	(23.30		)	(1,810	)	(26.95		)
Vested (end of performance period)	—		—			—		—			—		—
Nonvested at March 31, 2019	178,638		$	15.04		119,232		$	23.30		118,186		$	26.96

During the year ended December 31, 2018 and the three months ended March 31, 2019, the Partnership reduced its estimate of the number of phantom unit awards granted in 2018 and 2017 that are expected to vest and, as a result, unit-based compensation for the three months ended March 31, 2019 was $(0.2) million as compared to $0.8 million for the three months ended March 31, 2018.

Unit-based compensation is included in selling, general and administrative expenses. Unrecognized compensation cost related to performance-based phantom units totaled $0.5 million as of March 31, 2019 which is expected to be recognized over a weighted average period of 33 months.

Equity - Changes in Partnership Units

There were no changes in the number of Partnership units outstanding during the three months ended March 31, 2019.

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.

20

	Three Months Ended March 31,
	2019	2018
Weighted average limited partner common units - basic	22,733,977	22,725,346
Dilutive effect of unvested phantom units	5,632	61,543
Weighted average limited partner common units - dilutive	22,739,609	22,786,889

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, 2018	February 13, 2019	$0.6675	$	15,175	$	2,055	$	17,230

In addition, on April 26, 2019, the Partnership declared a cash distribution for the three months ended March 31, 2019, of $0.6675 per unit, totaling $17.2 million (including a $2.1 million IDR distribution). Such distributions are to be paid on May 14, 2019, to unitholders of record on May 7, 2019.

21

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, 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, 2018, as filed with the U.S. Securities and Exchange Commission (“SEC”) on March 14, 2019 (the “2018 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.

22

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 strategically located throughout the Northeast United States and in Quebec, Canada that have a combined storage tank capacity of 14.7 million barrels for refined products and other liquid materials, as well as 2.0 million square feet of materials handling capacity. We also have access to more than 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 Operation—Results of Operation 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 1,000 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 recent acquisition of Coen Energy, our customers include businesses engaged in the development of natural gas resources in Pennsylvania and surrounding states.

In our natural gas segment we purchase, sell and distribute natural gas to approximately 14,000 commercial and industrial customer locations across 13 states in the Northeast and Mid-Atlantic United States. We purchase the natural gas from natural gas producers and trading companies.

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, crude oil, clay slurry, salt, gypsum, 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.

23

As of March 31, 2019, our Sponsor, through its ownership of Sprague Holdings, owns 12,106,348 common units representing an aggregate of 53% 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.

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, prepaid forward contracts 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;

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

• The viability of acquisitions and capital expenditure projects.

EBITDA and adjusted EBITDA are not prepared in accordance with GAAP and should not be considered alternatives to net income (loss) 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;

24

• 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, prepaid forward contracts and natural gas transportation contracts, which are not marked to market for the purpose of recording unrealized gains or losses in net income. These adjustments align the unrealized hedging gains and losses to the period in which the revenue from the sale of inventory, prepaid fixed forwards and the utilization of transportation contracts relating to those hedges is realized in net income. Adjusted gross margin 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) and decreased by total commodity derivative gains and losses included in net income and increased by realized commodity derivative gains and losses included in net income, in each case with respect to refined products and natural gas inventory, prepaid forward contracts and natural gas transportation contracts. Adjusted gross margin has no impact on reported volumes or net sales.

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

• The economic results of our operations;

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

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

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

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

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

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

Operating Expenses

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

25

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 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.

26

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 show only the impact of hedging gains and losses actually realized in the period being reviewed. 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 2018 Annual Report for a discussion of the trends and factors that impact our business.

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 year 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)
	2019			2018			$			%
	(in thousands)
Net sales	$	1,258,308		$	1,331,148		$	(72,840	)	(5	)%
Cost of products sold (exclusive of depreciation and amortization)	1,159,112			1,183,982			(24,870		)	(2	)%
Operating expenses	23,789			23,209			580			2	%
Selling, general and administrative	20,913			27,864			(6,951		)	(25	)%
Depreciation and amortization	8,388			8,425			(37		)	—	%
Total operating costs and expenses	1,212,202			1,243,480			(31,278		)	(3	)%
Operating income	46,106			87,668			(41,562		)	(47	)%
Interest income	187			112			75			67	%
Interest expense	(11,959		)	(9,884		)	(2,075		)	21	%
Income before income taxes	34,334			77,896			(43,562		)	(56	)%
Income tax provision	(413		)	(2,975		)	2,562			(86	)%
Net income	$	33,921		$	74,921		$	(41,000	)	(55	)%

Analysis of Consolidated Operating Results

Net income was $33.9 million and $74.9 million for the three months ended March 31, 2019 and 2018, respectively and operating income was $46.1 million and $87.7 million for the three months ended March 31, 2019 and 2018, respectively. Operating results for the three months ended March 31, 2019 and 2018 include unrealized commodity derivative gains and losses with respect to refined products and natural gas inventory and natural gas transportation contracts of $3.8 million and $37.6 million, respectively. Excluding these unrealized items, operating income for the three months ended March 31, 2019 decreased $7.7 million, or 15%, as compared to the three months ended March 31, 2018.

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

27

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 - Non-GAAP Financial Measures” and “How Management Evaluates Our Results of Operations” of this report. The table below also presents information on weather conditions for the periods presented.

	Three Months Ended March 31,
	2019			2018
	(in thousands)
Reconciliation of Operating Income to Adjusted Gross Margin:
Operating income	$	46,106		$	87,668
Operating costs and expenses not allocated to operating segments:
Operating expenses	23,789			23,209
Selling, general and administrative	20,913			27,864
Depreciation and amortization	8,388			8,425
Add/(deduct):
Change in unrealized gain on inventory (1)	4,236			(23,561		)
Change in unrealized value on natural gas transportation contracts (2)	(7,988		)	(14,068		)
Total adjusted gross margin (3):	$	95,444		$	109,537
Adjusted Gross Margin by Segment:
Refined products (4)	$	44,739		$	56,335
Natural gas	32,322			37,948
Materials handling	16,451			13,148
Other operations	1,932			2,106
Total adjusted gross margin	$	95,444		$	109,537
Reconciliation of Net Income to Adjusted EBITDA
Net income	$	33,921		$	74,921
Add/(deduct):
Interest expense, net	11,772			9,772
Tax provision	413			2,975
Depreciation and amortization	8,388			8,425
EBITDA (3):	$	54,494		$	96,093
Add/(deduct):
Change in unrealized gain on inventory (1)	4,236			(23,561		)
Change in unrealized value on natural gas transportation contracts (2)	(7,988		)	(14,068		)
Biofuel tax credit (4)	—			(4,022		)
Acquisition related expenses (5)	8			443
Other adjustments (6)	171			194
Adjusted EBITDA	$	50,921		$	55,079
Other Data:
Ten Year Average Heating Degree Days (7)	2,657			2,657
Heating Degree Days (7)	2,620			2,576
Variance from average heating degree days	(1		)%	(3		)%
Variance from prior period heating degree days	2		%	5		%

28

(1) Inventory is valued at the lower of cost or net realizable value. The adjustment related to 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) On February 9, 2018, the U.S. federal government enacted legislation that reinstated an excise tax credit program available for certain of our biofuel blending activities. The program had expired on December 31, 2016 and was reinstated retroactively to January 1, 2017. During the three months ended March 31, 2018, we recorded excise tax credits of $4.0 million that relate to blending activities that occurred during the year ended December 31, 2017, resulting in an increase in adjusted gross margin during the period. We record the credit in the period the legislation was enacted as a reduction of cost of products sold (exclusive of depreciation and amortization) resulting in an increase in adjusted gross margin. This adjustment reflects the effect on our adjusted EBITDA had these credits been recorded in the period in which the blending activity took place.

(5) 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. 

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

(7) 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 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.

29

Analysis of Operating Segments

Three Months Ended March 31, 2019 compared to Three Months Ended March 31, 2018

	Three Months Ended March 31,				Increase/(Decrease)
	2019		2018		$			%
	(in thousands, except adjusted unit gross margin)
Volumes:
Refined products (gallons)	549,492		576,240		(26,748		)	(5	)%
Natural gas (MMBtus)	19,804		20,257		(453		)	(2	)%
Materials handling (short tons)	922		793		129			16	%
Materials handling (gallons)	106,223		69,972		36,251			52	%
Net Sales:
Refined products	$	1,120,123	$	1,180,860	$	(60,737	)	(5	)%
Natural gas	114,167		129,927		(15,760		)	(12	)%
Materials handling	16,481		13,148		3,333			25	%
Other operations	7,537		7,213		324			4	%
Total net sales	$	1,258,308	$	1,331,148	$	(72,840	)	(5	)%
Adjusted Gross Margin:
Refined products	$	44,739	$	56,335	$	(11,596	)	(21	)%
Natural gas	32,322		37,948		(5,626		)	(15	)%
Materials handling	16,451		13,148		3,303			25	%
Other operations	1,932		2,106		(174		)	(8	)%
Total adjusted gross margin	$	95,444	$	109,537	$	(14,093	)	(13	)%
Adjusted Unit Gross Margin:
Refined products	$	0.081	$	0.098	$	(0.017	)	(17	)%
Natural gas	$	1.632	$	1.873	$	(0.241	)	(13	)%

Refined Products

Refined products net sales decreased $60.7 million, or 5%, compared to the same period last year, due to a reduction in volume. The most significant cause of the 5% decline in volume was lower heavy fuel oil sales at both Kildair Services ULC ("Kildair") and Sprague, partly due to limited natural gas interruptions as well as reduced marine bunker activity driven by higher competitive intensity.  In addition, gasoline volumes were lower than last year due to fewer spot sales opportunities with gasoline prices rising steadily during the quarter. Distillate volumes were slightly lower, with increased diesel sales largely offsetting reduced heating oil volumes.

Refined products adjusted gross margin decreased $11.6 million, or 21%, compared to the same period last year. The decrease in adjusted gross margin was mostly due to the 17% reduction in average unit margins, with the lower volumes also a contributing factor. The unit margin decline was particularly evident in discretionary sales driven by the well-supplied market. The higher competitive intensity compared to the same period last year also was a notable factor impacting Kildair’s unit margins.

Natural Gas

Natural gas net sales declined $15.8 million, or 12%, compared to the same period last year due to a combination of a 10% decrease in sales prices and a 2% reduction in volume. The sales price decrease was consistent with the lower underlying natural gas price environment. The reduced volume was primarily due to higher competitive intensity in some markets along with the loss of a few higher volume accounts.

Natural gas adjusted gross margin decreased $5.6 million, or 15%, compared to the same period last year, primarily due to a 13% decrease in adjusted unit gross margin. The decline in adjusted unit gross margin was a combination of increased competitive intensity and fewer logistics optimization opportunities in the lower price and reduced market volatility environment.

30

Materials Handling

Materials handling net sales and adjusted gross margin of $16.5 million both increased approximately $3.3 million, or 25%, compared to the same period last year. Incremental revenue at Kildair was the primary factor due to a major increase in Vacuum Gas Oil (VGO) and Heavy Fuel Oil (HFO) tank rental agreement income from two customers, as well as a full three months of the asphalt materials handling agreement that began in March 2018 compared to only one month last year. At Sprague’s U.S. operations, gross margin increased slightly driven by a modest gain in liquid bulk activity primarily due to higher asphalt and clay slurry volumes.

Other Operations

Net sales from other operations increased $0.3 million, or 4%, as a result of the higher coal price environment compared to the same period last year. Adjusted gross margin decreased $0.2 million.

Operating Costs and Expenses

Three Months Ended March 31, 2019 compared to Three Months Ended March 31, 2018

	Three Months Ended March 31,				Increase/(Decrease)
	2019		2018		$			%
	(in thousands)
Operating expenses	$	23,789	$	23,209	$	580		2%
Selling, general and administrative	$	20,913	$	27,864	$	(6,951	)	(25)%
Depreciation and amortization	$	8,388	$	8,425	$	(37	)	0%
Interest expense, net	$	11,772	$	9,772	$	2,000		20%

Operating Expenses. Operating expenses increased $0.6 million, or 2%, compared to the same period last year, reflecting $0.3 million of increased insurance expense and $0.3 million of higher boiler fuel and utility expenses.

Selling, General and Administrative Expenses. SG&A expenses decreased $7.0 million, or 25%, compared to the same period last year. This decline was driven by a $5.5 million decrease in incentive compensation accruals, a $0.8 million decrease in sales commissions and a $0.4 million decrease in acquisition related expenses partially offset by a $0.6 million increase in severance expense associated with ongoing cost reduction initiatives.

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

Interest Expense, net. Interest expense, net increased $2.0 million, or 20%, compared to the same period last year primarily due to increased interest 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, 2019, we had working capital of $222.4 million.

As of March 31, 2019, the undrawn borrowing capacity under the working capital facilities of our Credit Agreement was $76.4 million and the undrawn borrowing capacity under the acquisition facility was $201.9 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 months ended March 31, 2019, the amount drawn under the working capital facilities of our Credit Agreement fluctuated from a low of $285.0 million to a high of $394.7 million.

31

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

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. Obligations under the Credit Agreement are secured by substantially all of the assets of the Partnership and its subsidiaries.

As of March 31, 2019, the revolving credit facilities under the Credit Agreement contained, among other items, the following:

• A U.S. dollar revolving working capital facility of up to $950.0 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 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 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, 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 and the multicurrency revolving working capital facility by $220.0 million, subject to a maximum combined increase for both facilities of $270.0 million in the aggregate. Additionally, subject to certain conditions, the revolving acquisition facility may be increased by $200.0 million.

Indebtedness under the Credit Agreement bears interest, at the borrowers' option, at a rate per annum equal to either (i) the Eurocurrency Rate (which is the LIBOR Rate for loans denominated in U.S. dollars and CDOR for loans denominated in Canadian dollars, in each case adjusted for certain regulatory costs) 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%.

The specified margin for the working capital facilities will range, based upon the percentage utilization of this facility, 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 the U.S. dollar working capital facility or the multicurrency working capital facility. The specified margin for the 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. In addition, the Partnership will incur a commitment fee on the unused portion of the facilities at a rate ranging from 0.375% to 0.50% per annum. Overdue amounts bear interest at the applicable rates described above plus an additional margin of 2%.

32

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 would not be in pro forma compliance with its 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 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 leverage-to-EBITDA ratio. The credit agreement also limits the Partnership's ability to incur debt, grant liens, make certain investments or acquisitions, dispose of assets, and incur additional indebtedness. The Partnership was in compliance with the covenants under the Credit Agreement at March 31, 2019.

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.

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements.

Capital Expenditures

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

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

	Capital Expenditures
	Expansion		Maintenance		Total
	(in thousands)
Three Months Ended March 31,
2019	$	1,069	$	1,124	$	2,193
2018	$	1,646	$	2,035	$	3,681

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,
	2019			2018
	(in thousands)
Net cash (used in) provided by operating activities	$	(2,975	)	$	56,735
Net cash used in investing activities	$	(2,171	)	$	(3,652	)
Net cash provided by (used in) financing activities	$	4,040		$	(54,286	)

33

Operating Activities

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

Net cash provided by operating activities for the three months ended March 31, 2018 was $56.7 million and was primarily driven by cash inflows as a result of a decrease of $101.2 million in inventories due to a seasonal reduction in inventory requirements, a decrease of $34.7 million in accounts receivable due to a seasonal reduction in sales volume, and $74.9 million in net income. These inflows were offset by cash outflows as a result of a reduction of $116.7 million in accounts payable and accrued liabilities primarily relating to the timing of invoice payments for product purchases and $60.8 million representing the net impact in our derivative instruments as a result of changes in commodity prices during the period.

Investing Activities

Net cash used in investing activities for the three months ended March 31, 2019 was $2.2 million of which $1.1 million related to expansion capital expenditures and $1.1 million related to maintenance capital expenditure projects across our terminal system.

Net cash used in investing activities for the three months ended March 31, 2018 was $3.7 million of which $1.6 million related to expansion capital expenditures and $2.0 million related to maintenance capital expenditure projects across our terminal system.

Financing Activities

Net cash provided by financing activities for the three months ended March 31, 2019 was $4.0 million, and primarily resulted from $22.5 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 million.

Net cash used in financing activities for the three months ended March 31, 2018 was $54.3 million, and primarily resulted from $33.0 million of payments under our Credit Agreement due to reduced financing requirements from accounts receivable levels, the reduction of seasonal inventory levels and distributions of $17.6 million.

Impact of Inflation

Inflation in the United States and Canada has been relatively low in recent years and did not have a material impact on our results of operations for the three months ended March 31, 2019 and 2018.

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.

34

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 2018 Annual Report and as updated in Note 3 to this Quarterly Report as it relates to the adoption of ASU 2016-02, Leases (Topic 842). Other than the impact of the adoption of the new lease guidance, 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.

Recent Accounting Pronouncements

For information on recent accounting pronouncements impacting our business, see "Recent Accounting Pronouncements" included under Note 1 to our Condensed Consolidated Financial Statements.

35

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 residual fuel oil. 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 periodically use the ethanol futures contracts (EH - CBOT Ethanol Futures and EZ - NY Ethanol Futures) to hedge ethanol that is used for blending into our gasoline. We also use Rotterdam Barge Gasoil 0.1% Sulfur 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 sets forth 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,
	(in thousands)
	2019			2018
Refined products contracts	$	(16,383	)	$	10,203
Natural gas contracts	13,379			872
Total	$	(3,004	)	$	11,075

Substantially all of our commodity derivative contracts outstanding as of March 31, 2019 will settle prior to September 30, 2020.

36

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, 2019 were as follows (in thousands):

Beginning	Ending	Notional Amount
January 2019	January 2020	$	300,000
January 2020	January 2021	$	300,000
January 2021	January 2022	$	300,000
January 2022	January 2023	$	250,000

During the two year period ended March 31, 2019 we hedged approximately 43% 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, 2019, we estimate that if short-term interest rates increased or decreased 100 basis points, our interest expense would have increased approximately $3.7 million and decreased approximately $3.7 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, 2019:

	As of March 31, 2019
	Fair Value Measurement		Active Markets Level 1		Observable Inputs Level 2		Unobservable Inputs Level 3
	(in thousands)
Derivative assets:
Commodity fixed forwards	$	45,913	$	14	$	45,899	$	—
Futures, swaps and options	30,273		30,223		50		—
Commodity derivatives	76,186		30,237		45,949		—
Interest rate swaps	1,795		—		1,795		—
Total derivative assets	$	77,981	$	30,237	$	47,744	$	—
Derivative liabilities:
Commodity fixed forwards	$	12,306	$	—	$	12,306	$	—
Futures, swaps and options	33,215		33,211		4		—
Commodity derivatives	45,521		33,211		12,310		—
Interest rate swaps	4,762		—		4,762		—
Currency swaps	4		—		4		—
Total derivative liabilities	$	50,287	$	33,211	$	17,076	$	—

37

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.

38

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, 2019, 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, 2019.

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, 2019 that have materially affected, or are reasonably likely to materially affect, the Partnership’s internal control over financial reporting.

39

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 captions Legal, Environmental and Other Proceedings in Note 10 - Commitments and Contingencies to our consolidated financial statements included in Part I, Item 1 of this Quarterly Report, which information is incorporated by reference into this Part II, Item 1.

Item 1A. Risk Factors

In addition to other information set forth in this report, you should carefully consider the factors discussed in Part I, Item 1A “Risk Factors” included in our 2018 Annual Report, which could materially affect our business, financial condition or future results.

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

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

40

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. 1 to the 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)).
3.4	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)).
3.5	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)).
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
101.SCH*	XBRL Taxonomy Extension Schema Document
101.CAL*	XBRL Taxonomy Extension Calculation
101.DEF*	XBRL Taxonomy Extension Definition
101.LAB*	XBRL Taxonomy Extension Label Linkbase
101.PRE*	XBRL Taxonomy Extension Presentation
*	Filed herewith.
**	Furnished herewith in accordance with Item 601(b)(32) of Regulation S-K.
***	Pursuant to Item 601(b)(2) of Regulation S-K, certain schedules to the Asset Purchase Agreements have been omitted. The registrant hereby agrees to furnish supplementally to the SEC, upon its request, any or all omitted schedules.

41

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 8, 2019		/s/ David C. Long
		David C. Long Chief Financial Officer (on behalf of the registrant, and in his capacity as Principal Financial Officer)

42