10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2018

or

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

For the transition period  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

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. (Check one):

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 November 1, 2018.

Table of Contents

		Page
PART I—FINANCIAL INFORMATION
Item 1.	Financial Statements:
	Condensed Consolidated Balance Sheets as of September 30, 2018 (unaudited) and December 31, 2017	1
	Unaudited Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2018 and September 30, 2017	2
	Unaudited Condensed Consolidated Statements of Comprehensive Income (Loss) for the three and nine months ended September 30, 2018 and September 30, 2017	3
	Unaudited Condensed Consolidated Statements of Unitholders’ Equity (Deficit) for the nine months ended September 30, 2018	4
	Unaudited Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2018 and September 30, 2017	5
	Notes to Unaudited Condensed Consolidated Financial Statements	6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	23
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	40
Item 4.	Controls and Procedures	43
PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	44
Item 1A.	Risk Factors	44
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	44
Item 3.	Defaults Upon Senior Securities	44
Item 4.	Mine Safety Disclosures	44
Item 5.	Other Information	44
Item 6.	Exhibits	45
Signatures		47

Part I – FINANCIAL INFORMATION

Item 1 — Condensed Consolidated Financial Statements

Sprague Resources LP

Condensed Consolidated Balance Sheets

(in thousands except unit amounts)

	September 30, 2018			December 31, 2017
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	18,621		$	6,815
Accounts receivable, net	190,770			316,613
Inventories	211,946			335,859
Fair value of derivative assets	50,466			107,254
Other current assets	19,754			39,946
Total current assets	491,557			806,487
Fair value of derivative assets, long-term	12,321			7,493
Property, plant and equipment, net	350,145			350,059
Intangibles, net	62,754			71,891
Other assets, net	9,496			12,018
Goodwill	115,037			115,037
Total assets	$	1,041,310		$	1,362,985
Liabilities and unitholders’ equity
Current liabilities:
Accounts payable	$	94,431		$	205,105
Accrued liabilities	46,310			49,038
Fair value of derivative liabilities	71,712			156,763
Due to General Partner	5,441			11,228
Current portion of working capital facilities	40,545			275,613
Current portion of other obligations	6,914			6,476
Total current liabilities	265,353			704,223
Commitments and contingencies
Working capital facilities - less current portion	195,855			66,237
Acquisition facility	379,100			383,500
Fair value of derivative liabilities, long-term	8,373			8,265
Other obligations - less current portion	48,567			49,625
Due to General Partner	2,016			1,678
Deferred income taxes	17,678			17,623
Total liabilities	916,942			1,231,151
Unitholders’ equity:
Common unitholders - public (10,620,936 units and 10,446,539 units issued and outstanding as of September 30, 2018 and December 31, 2017, respectively)	188,038			193,977
Common unitholders - affiliated (12,106,348 units issued and outstanding)	(58,032		)	(53,273		)
Accumulated other comprehensive loss, net of tax	(5,638		)	(8,870		)
Total unitholders’ equity	124,368			131,834
Total liabilities and unitholders’ equity	$	1,041,310		$	1,362,985

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

1

Sprague Resources LP

Unaudited Condensed Consolidated Statements of Operations

(in thousands except unit and per unit amounts)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
Net sales	$	618,455		$	491,393		$	2,691,259		$	1,922,826
Cost of products sold (exclusive of depreciation and amortization)	581,624			456,656			2,462,279			1,720,860
Operating expenses	21,047			16,891			66,537			50,624
Selling, general and administrative	16,923			17,559			63,349			63,472
Depreciation and amortization	8,343			6,655			25,146			19,537
Total operating costs and expenses	627,937			497,761			2,617,311			1,854,493
Operating (loss) income	(9,482		)	(6,368		)	73,948			68,333
Other income	293			—			293			183
Interest income	123			75			404			247
Interest expense	(9,073		)	(7,170		)	(28,369		)	(22,604		)
(Loss) income before income taxes	(18,139		)	(13,463		)	46,276			46,159
Income tax provision	(295		)	(853		)	(2,984		)	(3,768		)
Net (loss) income	(18,434		)	(14,316		)	43,292			42,391
Incentive distributions declared	(2,055		)	(1,024		)	(5,824		)	(2,620		)
Limited partners’ interest in net (loss) income	$	(20,489	)	$	(15,340	)	$	37,468		$	39,771
Net (loss) income per limited partner unit:
Common - basic	$	(0.90	)	$	(0.68	)	$	1.65		$	1.80
Common - diluted	$	(0.90	)	$	(0.68	)	$	1.65		$	1.78
Units used to compute net (loss) income per limited partner unit:
Common - basic	22,727,284			22,543,527			22,726,645			22,093,578
Common - diluted	22,727,284			22,543,527			22,766,725			22,368,432
Distribution declared per unit	$	0.6675		$	0.6225		$	1.9875		$	1.8225

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

2

Sprague Resources LP

Unaudited Condensed Consolidated Statements of Comprehensive Income (Loss)

(in thousands)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
Net (loss) income	$	(18,434	)	$	(14,316	)	$	43,292		$	42,391
Other comprehensive income, net of tax:
Unrealized gain on interest rate swaps
Net gain arising in the period	1,503			410			4,734			699
Reclassification adjustment related to gain realized in income	(619		)	(129		)	(1,398		)	(13		)
Net change in unrealized gain on interest rate swaps	884			281			3,336			686
Tax effect	(7		)	(3		)	(25		)	(10		)
	877			278			3,311			676
Foreign currency translation adjustment	48			139			(79		)	249
Other comprehensive income	925			417			3,232			925
Comprehensive (loss) income	$	(17,509	)	$	(13,899	)	$	46,524		$	43,316

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			Subordinated- Sprague Holdings			Incentive Distribution Rights			Accumulated Other Comprehensive Loss			Total
Balance at December 31, 2016	$	175,314		$	(4,518	)	$	(34,576	)	$	—		$	(10,783	)	$	125,437
Conversion of subordinated units to common units	—			(40,393		)	40,393			—			—			—
Net income	11,955			14,324			—			3,218			—			29,497
Other comprehensive income	—			—			—			—			1,913			1,913
Unit-based compensation	1,034			1,240			—			—			—			2,274
Distributions paid	(25,198		)	(23,239		)	(5,817		)	(3,218		)	—			(57,472		)
Common units issued related to Carbo acquisition	31,401			—			—			—			—			31,401
Common units issued with annual bonus	161			210			—			—			—			371
Units withheld for employee tax obligations	(690		)	(897		)	—			—			—			(1,587		)
Balance at December 31, 2017	$	193,977		$	(53,273	)	$	—		$	—		$	(8,870	)	$	131,834
Net income	17,828			20,323			—			5,141			—			43,292
Other comprehensive income	—			—			—			—			3,232			3,232
Unit-based compensation	(43		)	(48		)	—			—			—			(91		)
Distributions paid	(22,552		)	(23,698		)	—			(5,141		)	—			(51,391		)
Units withheld for employee tax obligations	(1,172		)	(1,336		)	—			—			—			(2,508		)
Balance at September 30, 2018	$	188,038		$	(58,032	)	$	—		$	—		$	(5,638	)	$	124,368

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

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Sprague Resources LP

Unaudited Condensed Consolidated Statements of Cash Flows

(in thousands)

	Nine Months Ended September 30,
	2018			2017
Cash flows from operating activities
Net income	$	43,292		$	42,391
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization (includes amortization of deferred debt issuance costs)	27,802			23,881
Gain on sale of assets and insurance recoveries	(266		)	(101		)
Changes in fair value of contingent consideration	521			—
Provision for doubtful accounts	942			(251		)
Non-cash unit-based compensation	(91		)	1,688
Other	75			—
Deferred income taxes	(49		)	953
Changes in assets and liabilities:
Accounts receivable	124,901			77,660
Inventories	123,913			73,944
Other assets	20,185			14,040
Fair value of commodity derivative instruments	(29,649		)	(19,813		)
Due to General Partner and affiliates	(5,449		)	(6,977		)
Accounts payable, accrued liabilities and other	(114,825		)	(80,524		)
Net cash provided by operating activities	191,302			126,891
Cash flows from investing activities
Purchases of property, plant and equipment	(13,333		)	(39,774		)
Business acquisitions	—			(72,184		)
Proceeds from property insurance settlement and sale of assets	377			911
Net cash used in investing activities	(12,956		)	(111,047		)
Cash flows from financing activities
Net (payments) borrowings under credit agreements	(109,454		)	35,003
Payments on capital leases, term debt, and other obligations	(3,019		)	(1,977		)
Debt issue costs	(182		)	(4,483		)
Distributions to unitholders	(51,391		)	(42,409		)
Foreign exchange on capital lease obligations	(17		)	—
Repurchased units withheld for employee tax obligations	(2,508		)	(1,587		)
Net cash used in financing activities	(166,571		)	(15,453		)
Effect of exchange rate changes on cash balances held in foreign currencies	31			121
Net change in cash and cash equivalents	11,806			512
Cash and cash equivalents, beginning of period	6,815			2,682
Cash and cash equivalents, end of period	$	18,621		$	3,194
Supplemental disclosure of cash flow information
Cash paid for interest	$	25,443		$	18,293
Cash paid for taxes	$	3,497		$	1,601
Non-cash consideration related to acquisition:
Common units issued - Carbo	$	—		$	31,401
Deferred consideration obligation - Carbo	$	—		$	27,284

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. Unless the context otherwise requires, 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.

• 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 our revenue activities within these business segments.

Prior to February 16, 2017, Sprague Holdings owned, directly or indirectly, all of the Partnership’s subordinated units. The principal difference between the Partnership’s common units and subordinated units is that during the subordination period, the common units had the right to receive a minimum quarterly distribution of $0.4125 per common unit, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of cash from distributable cash flow could be made on the subordinated units. On February 16, 2017, based upon meeting certain distribution and performance tests provided in the Partnership's partnership agreement, all 10,071,970 subordinated units outstanding converted to common units on a one-for-one basis.

As of September 30, 2018, 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 Note13 "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

6

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, 2017 as filed with the SEC on March 14, 2018 (the “2017 Annual Report”).

The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities in the balance sheet and the reported net sales and expenses in the income statement. Actual results could differ from those estimates. Among the estimates made by management are asset and liability valuations as part of an acquisition, 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 September 30, 2018 and December 31, 2017, the consolidated results of operations for the three and nine months ended September 30, 2018 and 2017, and the consolidated cash flows for the nine months ended September 30, 2018 and 2017. 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 2017 Annual Report and are the same as are used in preparing these unaudited interim Condensed Consolidated Financial Statements except for the adoption of ASU 2014-09, Revenue from Contracts with Customers (Topic 606) which the Partnership adopted as of January 1, 2018.The adoption of Topic 606 is discussed further in Recent Accounting Pronouncements below as well as in Note 2 "Revenue".

Recent Accounting Pronouncements

In July 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2017-12, Derivatives and Hedging: 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 Partnership is currently evaluating the impact of this new standard on the 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 January 2017, the FASB issued ASU 2017-01 Business Combinations (Topic 805), whichclarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. This ASU is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. The Partnership will follow this new guidance for transactions entered into after December 31, 2017.

In August 2016, the FASB issued ASU 2016-15 Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments, which addresses eight specific cash flow issues with the objective of reducing diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows under Topic 230, Statement of Cash Flows, and other Topics. This ASU is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years and is to be applied retrospectively to all periods presented. The adoption of this guidance in 2018 did not have an impact on the Partnership's consolidated statements of cash flows.

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In February 2016, the FASB issued ASU 2016-02 Leases (Topic 842), which, among other things, requires lessees to recognize at the commencement date of a lease a liability, which is a lessee's 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. This ASU is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. In June 2018, the FASB issued ASU 2018-11 that introduced a transition option, that the Partnership intends to adopt, that will allow the new standard to be adopted without revising comparative period reporting or disclosures. The Partnership has started the process of gathering and analyzing its lease contracts and is in the process of evaluating changes to business processes, systems and controls needed to support recognition and disclosure under this new standard. While the adoption of this new standard is expected to result in an increase to reported assets and liabilities, the Partnership has not yet determined the full impact that the adoption of ASU 2016-02 will have on its consolidated financial statements.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606), which revises the

principles of revenue recognition from one based on the transfer of risks and rewards to when a customer obtains control of a

good or service. The FASB issued several ASUs after ASU 2014-09 to clarify implementation guidance but did not change the core principle of the guidance in Topic 606. These ASUs are effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. The adoption of this standard in 2018 did not have an impact on the Partnership's consolidated financial statements nor result in significant changes to business processes, systems, or internal controls.

2. Revenue

Accounting Policies

Revenue is recognized when performance obligations under the terms of a contract with a customer are satisfied. The majority of the Partnership’s revenue is generated from refined products and natural gas contracts that have a single performance obligation which is the delivery of the related energy product. Accordingly, the Partnership recognizes revenue for refined products and natural gas when title and risk of loss have been transferred to the customer which is generally at the time of shipment or delivery of products. Revenue for the Partnership’s materials handling segment is recorded on a straight-line basis under leasing arrangements or as services are performed.

Revenue is measured as the amount of consideration the Partnership expects to receive in exchange for transferring products or providing services and is generally based upon a negotiated index, formula, list or fixed price. An allowance for doubtful accounts is recorded to reflect an estimate of the ultimate realization of the Partnership's accounts receivable and includes an assessment of the customers’ creditworthiness and the probability of collection. Estimated discounts are included in the transaction price of the contracts with customers as a reduction to net sales. The Partnership sells its products or provides its services directly to commercial customers and wholesale distributors generally under agreements with payment terms typically less than 30 days.

The Partnership has elected to account for shipping and handling as activities to fulfill the promise to transfer the good. As such, shipping and handling fees billed to customers in a sales transaction are recorded in net sales and shipping and handling costs incurred are recorded in cost of products sold (exclusive of depreciation and amortization). The Partnership has elected to exclude from net sales any value add, sales and other taxes which it collects concurrently with revenue-producing activities. These accounting policy elections are consistent with the way the Partnership historically recorded shipping and handling fees and taxes.

The majority of the Partnership's revenue is derived from contracts (i) with an original expected length of one year or less and (ii) contracts for which it recognizes revenue at the amount in which it has the right to invoice the customer as product is delivered. The Partnership has elected the practical expedient not to disclose the value of remaining performance obligations associated with these types of contracts.

Contract Balances

Contract liabilities primarily relate to advances or deposits received from the Partnership's customers before revenue is recognized. These amounts are included in accrued liabilities and amounted to $7.8 million and $7.7 million as of September 30, 2018 and December 31, 2017, respectively. A substantial portion of the contract liabilities as of December 31, 2017 remains outstanding as of September 30, 2018 as they are primarily deposits. The Partnership does not have any material contract assets as of September 30, 2018 or December 31, 2017.

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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. 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 includes the purchase and distribution of coal, certain commercial trucking activities and a heating equipment service business. Revenue from other activities 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 September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
Net sales:
Refined products
Distillates	$	403,186	$	279,381	$	1,890,740	$	1,217,866
Gasoline	88,536		71,971		252,852		208,669
Heavy fuel oil and asphalt	59,767		74,140		252,782		211,531
Total refined products	$	551,489	$	425,492	$	2,396,374	$	1,638,066
Natural gas	46,908		49,694		235,263		235,068
Materials handling	14,711		11,395		42,077		34,118
Other operations	5,347		4,812		17,545		15,574
Net sales	$	618,455	$	491,393	$	2,691,259	$	1,922,826
Net sales by Country:
United States	$	549,477	$	408,897	$	2,485,922	$	1,735,778
Canada	$	68,978	$	82,496	$	205,337	187,048
Net sales	$	618,455	$	491,393	$	2,691,259	$	1,922,826

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3. Business Combinations

The Partnership completed five business acquisitions during the year ended December 31, 2017 as described below. Allocations of the purchase price to the assets acquired and liabilities assumed have been made to record, where applicable, inventory, derivative assets and liabilities, natural gas transportation assets and liabilities, property, plant and equipment, identifiable intangible assets such as customer relationships and non-compete agreements as well as goodwill. If the results of these businesses had been included in the consolidated results of the Partnership for the entire three and nine months ended September 30, 2017, unaudited consolidated pro forma net sales would have been $514.0 million and $2,025.0 million, respectively, while the unaudited pro forma net (loss) income for the three months and nine months ended September 30, 2017 would not have been materially different.

The Partnership recognized less than $0.1 million and $0.7 million of acquisition related costs during the three months ended September 30, 2018 and 2017, and $0.7 million and $1.7 million for the nine months ended September 30, 2018 and 2017, respectively, which are included in selling, general and administrative expense.

Year Ended December 31, 2017

Coen Energy

On October 1, 2017, the Partnership purchased the membership interests of Coen Energy, LLC and Coen Transport, LLC as well as assets consisting of four bulk plants and underlying real estate (collectively, “Coen Energy”). Coen Energy, located in Washington, PA, provides energy products to commercial and residential customers located in Pennsylvania, Ohio and West Virginia. The Coen Energy business also provides energy fuel services to customers that are engaged in Marcellus and Utica shale drilling operations. The Coen Energy business is supported by four in-land bulk plants, two throughput locations, approximately 100 delivery vehicles and approximately 250 employees as of December 31, 2017. Initial consideration paid was $35.3 million in cash, not including the purchase of inventory and other adjustments, which was financed with borrowings under the Credit Agreement. Contingent consideration of up to $12.0 million is payable based on achieving certain economic performance measures during the three year period ending September 30, 2020. The operations of Coen Energy have been included in the Partnership's refined products segment since the acquisition date.

The following table summarizes the fair values of the assets acquired and liabilities assumed at the acquisition date:

Inventories	$	567
Other current assets	115
Property, plant and equipment	12,972
Intangibles	18,375
Total identifiable assets acquired	32,029
Other liabilities	(256		)
Net identifiable assets acquired	31,773
Goodwill	13,095
Net assets acquired	$	44,868

The goodwill recognized is primarily attributable to Coen Energy’s reputation in its geographic market area, the in-place workforce and the residual cash flow the Partnership believes that it will be able to generate.

Carbo Terminals    

On April 18, 2017, the Partnership acquired substantially all of the assets of Carbo Industries, Inc. and certain of its affiliates (together “Carbo”) by purchasing Carbo's Inwood and Lawrence, New York refined product terminal assets and its associated wholesale distribution business. The fair value of the consideration totaled $72.0 million and consisted of $13.3 million in cash that was financed through borrowings under the Credit Agreement, an obligation to pay $38.2 million over a ten year period (estimated net present value of $27.3 million) and $31.4 million in unregistered common units. The Carbo terminals have a combined gasoline, ethanol and distillate storage capacity of 174,000 barrels and are supplied primarily by pipeline with the ability to also accept product deliveries by barge and truck. The operations of Carbo are included in the Partnership's refined products segment since the acquisition date.

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The following table summarizes the fair values of the assets acquired and liabilities assumed at the acquisition date:

Inventories	$	3,220
Derivative and other current assets	111
Property, plant and equipment	22,995
Intangibles	29,000
Total identifiable assets acquired	55,326
Other liabilities	(188		)
Net identifiable assets acquired	55,138
Goodwill	16,718
Net assets acquired	$	71,856

The goodwill recognized is primarily attributable to Carbo’s reputation in the New York City area, the in-place workforce and the residual cash flow the Partnership believes that it will be able to generate.

Capital Terminal

On February 10, 2017, the Partnership purchased the East Providence, Rhode Island refined product terminal business of Capital Properties Inc. (the “Capital Terminal”). Consideration paid was $22.0 million and was financed with borrowings under the Credit Agreement. The terminal’s distillate storage capacity of 1.0 million barrels had been leased by the Partnership since April 2014 and was previously included in the Partnership’s total storage capacity. The operations of the Capital Terminal are included in the Partnership's refined products segment since the acquisition date.

The following table summarizes the fair values of the assets acquired and liabilities assumed at the acquisition date:

Property, plant and equipment	$	21,960
Accrued liabilities and other, net	(22		)
Net assets acquired	$	21,938

Global Natural Gas & Power

On February 1, 2017, the Partnership purchased the natural gas marketing and electricity brokering business of Global Partners LP ("Global Natural Gas & Power") for $17.3 million, not including the purchase of natural gas inventory, assumption of derivative assets (liabilities) and other adjustments. Consideration paid was $16.3 million and was financed with borrowings under the Credit Agreement. This business markets natural gas and electricity to commercial, industrial, municipal and institutional customer locations in the Northeast United States. The operations of Global Natural Gas & Power are included in the Partnership's natural gas segment since the acquisition date.

    The following table summarizes the fair values of the assets acquired and liabilities assumed at the acquisition date:

Inventory	$	286
Derivative assets	5,873
Natural gas transportation assets	695
Derivative assets long term	1,089
Natural gas transportation assets long term	378
Intangibles	5,046
Total identifiable assets acquired	13,367
Derivative liabilities	(4,865		)
Natural gas transportation liabilities	(465		)
Derivative liabilities long term	(1,214		)
Natural gas transportation liabilities long term	(162		)
Net identifiable assets acquired	6,661
Goodwill	9,592
Net assets acquired	$	16,253

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The goodwill recognized is primarily attributable to Global Natural Gas & Power’s reputation in its market regions, the in-place workforce and the residual cash flow the Partnership believes that it will be able to generate.

L.E. Belcher Terminal

On February 1, 2017, the Partnership purchased the Springfield, Massachusetts refined product terminal assets of Leonard E. Belcher, Incorporated (“L.E. Belcher”) for approximately $20.0 million, not including the purchase of inventory, assumption of derivative assets (liabilities) and other adjustments. Consideration paid was $20.7 million and was financed with borrowings under the Credit Agreement. The purchase consists of two pipeline-supplied distillate terminals and one distillate storage facility with a combined capacity of 283,000 barrels, as well as L.E. Belcher’s associated wholesale and commercial fuels businesses. The operations of L.E. Belcher are included in the Partnership's refined products segment since the acquisition date.

The following table summarizes the fair values of the assets acquired and liabilities assumed at the acquisition date:

Inventories	$	632
Derivative and other current assets	658
Property, plant and equipment	9,152
Intangibles	5,800
Total identifiable assets acquired	16,242
Derivative and other current liabilities	(680		)
Net identifiable assets acquired	15,562
Goodwill	5,081
Net assets acquired	$	20,643

The goodwill recognized is primarily attributable to L.E. Belcher's reputation in the Springfield, Massachusetts area, the in-place workforce and the residual cash flow the Partnership believes that it will be able to generate.

4. Accumulated Other Comprehensive Loss, Net of Tax

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

	September 30, 2018			December 31, 2017
Fair value of interest rate swaps, net of tax	$	5,899		$	2,588
Cumulative foreign currency translation adjustment	(11,537		)	(11,458		)
Accumulated other comprehensive loss, net of tax	$	(5,638	)	$	(8,870	)

5. Inventories

	September 30, 2018		December 31, 2017
Petroleum and related products	$	207,975	$	329,712
Coal	821		3,712
Natural gas	3,150		2,435
Inventories	$	211,946	$	335,859

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6. Credit Agreement

	September 30, 2018			December 31, 2017
Working capital facilities	$	236,400		$	341,850
Acquisition facility	379,100			383,500
Total credit agreement	615,500			725,350
Less: current portion of working capital facilities	(40,545		)	(275,613		)
Long-term portion	$	574,955		$	449,737

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 September 30, 2018, 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 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 September 30, 2018 and December 31, 2017, had a borrowing base of $402.4 million and $623.2 million, respectively. As of September 30, 2018 and December 31, 2017, outstanding letters of credit were $41.3 million and $72.3 million, respectively. As of September 30, 2018, excess availability under the working capital facilities was $124.7 million and excess availability under the acquisition facilities was $170.9 million.

The weighted average interest rate was 5.0% and 4.2% at September 30, 2018 and December 31, 2017, respectively. No amounts are due under the Credit Agreement until the maturity date, however, the current portion of the Credit Agreement at September 30, 2018 and December 31, 2017 represents the amounts of the working capital facility intended to be repaid during the following twelve month period.

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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 September 30, 2018, 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 $24.5 million and $19.7 million for the three months ended September 30, 2018 and 2017, and $87.4 million and $67.9 million for the nine months endedSeptember 30, 2018 and 2017, respectively. Through the General Partner, the Partnership also participates in the Parent’s pension and other post-retirement benefits. At September 30, 2018 and December 31, 2017, total amounts due to the General Partner with respect to these benefits and overhead costs were $7.5 million and $12.9 million, respectively.

8. Segment Reporting

The Partnership has four reporting segments that comprise the structure used by the chief operating decision makers (CEO and CFO/COO) 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 reporting segments are refined products, natural gas, materials handling and other activities.

The Partnership's refined products reporting segment purchases a variety of refined products, such as heating oil, diesel fuel, residual fuel oil, asphalt, 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 reporting segment consists of three operating segments.

The Partnership's natural gas reporting 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 reporting segment consists of one operating segment.

The Partnership's materials handling reporting 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 reporting segment consists of two operating segments.

The Partnership's other reporting segment includes the purchase, sale and distribution of coal, commercial trucking activities unrelated to its refined products segment and a heating equipment service business. 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 and nine months ended September 30, 2018 and 2017, respectively. The Partnership’s foreign sales, primarily sales of refined products and natural gas to its customers in Canada, were $69.0 million and $82.5 million for the three months ended September 30, 2018 and 2017, and $205.3 million and $187.0 million for the nine months ended September 30, 2018 and 2017, respectively.

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	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
Net sales:
Refined products	$	551,489		$	425,492		$	2,396,374		$	1,638,066
Natural gas	46,908			49,694			235,263			235,068
Materials handling	14,711			11,395			42,077			34,118
Other operations	5,347			4,812			17,545			15,574
Net sales	$	618,455		$	491,393		$	2,691,259		$	1,922,826
Adjusted gross margin (1):
Refined products	$	26,646		$	32,014		$	111,652		$	95,307
Natural gas	3,007			3,197			46,010			44,355
Materials handling	14,683			11,395			42,100			34,118
Other operations	1,715			1,897			5,496			5,800
Adjusted gross margin	46,051			48,503			205,258			179,580
Reconciliation to operating (loss) income (2):
Add/(deduct):
Unrealized (gain) loss on inventory (3)	(3,281		)	(13,673		)	19,309			15,374
Unrealized loss on prepaid forward contracts (4)	—			667			—			907
Unrealized (gain) loss on natural gas transportation contracts (5)	(5,939		)	(760		)	4,413			6,105
Operating costs and expenses not allocated to operating segments:
Operating expenses	(21,047		)	(16,891		)	(66,537		)	(50,624		)
Selling, general and administrative	(16,923		)	(17,559		)	(63,349		)	(63,472		)
Depreciation and amortization	(8,343		)	(6,655		)	(25,146		)	(19,537		)
Operating (loss) income	(9,482		)	(6,368		)	73,948			68,333
Other income	293			—			293			183
Interest income	123			75			404			247
Interest expense	(9,073		)	(7,170		)	(28,369		)	(22,604		)
Income tax provision	(295		)	(853		)	(2,984		)	(3,768		)
Net (loss) income	$	(18,434	)	$	(14,316	)	$	43,292		$	42,391

(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) loss on inventory which is not included in net income (loss), 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) The unrealized loss on prepaid forward contracts represents the Partnership’s estimate of the change in fair value of the prepaid forward contracts which are not recorded in net income until the forward contract is settled in the future (i.e., when the commodity is delivered to the customer). As these contracts are prepaid, they do not qualify as derivatives and changes in the fair value are therefore not included in net income. The fair value of the derivatives the Partnership uses to economically hedge its prepaid forward contracts declines or appreciates in value as the value of the underlying prepaid forward contract appreciates or declines, which creates unrealized hedging gains (losses) that are included in net income.

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(5) The unrealized (gain) loss on natural gas transportation contracts 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 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 as of each period end.

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 September 30, 2018, 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 September 30, 2018 and December 31, 2017, the carrying amounts of cash, cash equivalents and accounts receivable approximated fair value because of the short maturity of these instruments. As of September 30, 2018 and December 31, 2017, 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 September 30, 2018 and December 31, 2017, 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 September 30, 2018, 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 September 30, 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	$	14,209	$	—	$	14,209	$	—
Futures, swaps and options	42,571		42,566		5		—
Commodity derivatives	56,780		42,566		14,214		—
Interest rate swaps	5,993		—		5,993		—
Other	14		—		14		—
Total derivative assets	$	62,787	$	42,566	$	20,221	$	—
Derivative liabilities:
Commodity fixed forwards	$	42,175	$	—	$	42,175	$	—
Futures, swaps and options	37,862		37,858		4		—
Commodity derivatives	80,037		37,858		42,179		—
Interest rate swaps	48		—		48		—
Total derivative liabilities	$	80,085	$	37,858	$	42,227	$	—
Contingent consideration	$	10,246	$	—	$	—	$	10,246

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	As of December 31, 2017
	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	$	11,502	$	—	$	11,502	$	—
Futures, swaps and options	100,630		100,613		17		—
Commodity derivatives	112,132		100,613		11,519		—
Interest rate swaps	2,615		—		2,615		—
Total derivative assets	$	114,747	$	100,613	$	14,134	$	—
Derivative liabilities:
Commodity fixed forwards	$	61,195	$	—	$	61,195	$	—
Futures, swaps and options	103,827		103,654		173		—
Commodity derivatives	165,022		103,654		61,368		—
Interest rate swaps	6		—		6		—
Total derivative liabilities	$	165,028	$	103,654	$	61,374	$	—
Contingent consideration	$	9,725	$	—	$	—	$	9,725

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. Substantially all of the Partnership’s commodity derivative contracts outstanding as of September 30, 2018 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:

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

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

Fair value measurements based on Level 3 inputs: Measurements that are least observable are estimated from significant unobservable inputs determined from sources with little or no market activity for comparable contracts or for positions with longer durations. The Partnership 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 September 30, 2018 and December 31, 2017.

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 $25.4 million at September 30, 2018. Information related to these offsetting arrangements is set forth below:

	As of September 30, 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	$	56,780		$	(37,423	)	$	—	$	19,357
Interest rate swap derivative assets	5,993			—			—		5,993
Other	14			—			—		14
Fair value of derivative assets	$	62,787		$	(37,423	)	$	—	$	25,364
Commodity derivative liabilities	$	(80,037	)	$	37,423		$	10,121	$	(32,493	)
Interest rate swap derivative liabilities	(48		)	—			—		(48		)
Fair value of derivative liabilities	$	(80,085	)	$	37,423		$	10,121	$	(32,541	)

	As of December 31, 2017
				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	$	112,132		$	(86,493	)	$	(4,303	)	$	21,336
Interest rate swap derivative assets	2,615			—			—			2,615
Fair value of derivative assets	$	114,747		$	(86,493	)	$	(4,303	)	$	23,951
Commodity derivative liabilities	$	(165,022	)	$	86,493		$	20,975		$	(57,554	)
Interest rate swap derivative liabilities	(6		)	—			—			(6		)
Fair value of derivative liabilities	$	(165,028	)	$	86,493		$	20,975		$	(57,560	)

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
Refined products contracts	$	1,087		$	(17,281	)	$	10,063		$	27,637
Natural gas contracts	(6,244		)	(908		)	(9,204		)	13,850
Total	$	(5,157	)	$	(18,189	)	$	859		$	41,487

There were no discretionary trading activities for the three and nine months ended September 30, 2018 and 2017. The following table presents gross volume of commodity derivative instruments outstanding for the periods indicated:

	As of September 30, 2018				As of December 31, 2017
	Refined Products (Barrels)		Natural Gas (MMBTUs)		Refined Products (Barrels)		Natural Gas (MMBTUs)
Long contracts	4,552		126,453		9,255		133,532
Short contracts	(6,837	)	(71,121	)	(13,487	)	(72,074	)

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 actual and forecasted LIBOR borrowings and have been designated as cash flow hedges. Counterparties to the Partnership’s interest rate swaps are large multinational banks and the Partnership does not believe there is a material risk of counterparty non-performance.

The Partnership's interest rate swap agreements outstanding as of September 30, 2018 were as follows:

Beginning	Ending	Notional Amount
January 2018	January 2019	$	275,000
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 and nine months ended September 30, 2018 and 2017.

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 September 30, 2018, the amount of unrealized gains, net of tax, expected to be reclassified to earnings during the following twelve-month period was $1.9 million.

Contingent Consideration

As part of the Coen Energy acquisition in 2017, the Partnership may be 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 statements of operations.

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The Partnership records changes in the estimated fair value of the contingent consideration within selling, general and administrative expenses in the condensed consolidated statements of operations. Changes in the contingent consideration liability are measured at fair value on a recurring basis using unobservable inputs (Level 3) and during fiscal 2018 are as follows:

Contingent consideration - December 31, 2017	$	9,725
Change in estimated fair value	521
Contingent consideration - September 30, 2018	$	10,246

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. After filing legal action, the Partnership has been assessed $3.5 million of tax, including interest and penalties, for the period of 2013 to 2017, and has provided requested information for previous years. During September 2018, the Partnership received an assessment of $7.3 million, excluding a 15% penalty and interest, from the Ministry of Sustainable Development, Environment, and the Fight Against Climate Change (known as MDDELCC) under separate regulation that was in effect for the period from 2007 through 2014. The Partnership is disputing the MDDELCC 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, 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). Upon vesting, a holder of performance-based phantom units is entitled to receive a number of common units of the Partnership equal to a percentage (between 0 and 200%) of the phantom units granted, based on the Partnership’s achieving pre-determined performance criteria. The Partnership uses authorized but unissued units to satisfy its unit-based obligations.

OCF-based Phantom Units

Phantom unit awards granted in 2018, 2017 and 2016 include a performance criteria that considers Sprague Holdings operating cash flow, as defined ("OCF"), over a three year performance 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 related to the OCF based awards is estimated each reporting period by multiplying the number of common units underlying such awards that, based on the Partnership's estimate of OCF, are probable to vest, by the grant-date fair value of the award and is recognized over the requisite service period using the straight-line method. The fair value of the OCF based phantom units is the grant date closing price listed on the New York Stock Exchange. 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.

Distribution Equivalent Rights

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.

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A summary of the Partnership’s unit awards subject to vesting during the nine months ended September 30,2018 is set forth below:

	2018 Awards					2017 Awards					2016 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, 2017	—		$	—		131,000		$	26.96		163,900		$	17.52
Granted	143,981		23.30			—		—			—		—
Forfeited	(5,460	)	(23.30		)	(3,208	)	(26.95		)	(1,202	)	(17.52		)
Vested	—		—			—		—			—		—
Nonvested at September 30, 2018	138,521		$	23.30		127,792		$	26.96		162,698		$	17.52

During the nine-months ended September 30, 2018, the Partnership reduced its estimates of the number of units expected to vest over the vesting periods and as a result unit-based compensation for the three and nine months ended September 30,2018 was $(0.3) million and $(0.1) million, respectively, as compared to $(0.2) million and $1.7 million, for the three and nine months ended September 30,2017. Unit-based compensation is included in selling, general and administrative expenses. Unrecognized compensation cost related to performance-based phantom unit awards totaled $3.5 million as of September 30, 2018 which is expected to be recognized over a weighted average period of 14 months.

Equity - Changes in Partnership Units

Phantom units with a performance period ended as of December 31, 2017 vested at the 195.5% level and as a result 271,748 common units (vested market value of $7.0 million) were issued during January 2018, with 97,351 units being withheld to satisfy tax withholding requirements.

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

	Common Units
	Public	Sprague Holdings	Subordinated Units
Balance as of December 31, 2016	9,207,473	2,034,378	10,071,970
Conversion of subordinated units	—	10,071,970	(10,071,970	)
Units issued in connection with performance awards	89,315	—	—
Units issued in connection with employee bonus	8,840	—	—
Director vested awards	9,360	—	—
Units issued in connection with Carbo acquisition	1,131,551	—	—
Balance as of December 31, 2017	10,446,539	12,106,348	—
Units issued in connection with performance awards	174,397	—	—
Balance as of September 30, 2018	10,620,936	12,106,348	—

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 (loss), after deducting any incentive distributions, by the weighted-average number of outstanding common and subordinated 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.

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Payments made to the Partnership’s unitholders are determined in relation to actual distributions declared and are not based on the net income (loss) allocations used in the calculation of earnings (loss) per unit. Quarterly net income (loss) per limited partner and per unit amounts are stand-alone calculations and may not be additive to year to date amounts due to rounding and changes in outstanding units.

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

	Three Months Ended September 30,		Nine Months Ended September 30,
	2018	2017	2018	2017
Weighted average limited partner common units - basic	22,727,284	22,543,527	22,726,645	22,093,578
Dilutive effect of unvested phantom units	—	—	40,080	274,854
Weighted average limited partner common units - dilutive	22,727,284	22,543,527	22,766,725	22,368,432

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:

Three Months Ended	Payment Date	Per Unit	Common		IDR		DER		Total
December 31, 2017	February 12, 2018	$0.6375	$	14,489	$	1,373	$	1,760	$	17,622
March 31, 2018	May 18, 2018	$0.6525	$	14,830	$	1,714	$	—	$	16,544
June 30, 2018	August 10, 2018	$0.6675	$	15,170	$	2,055	$	—	$	17,225

In addition, on October 26, 2018, the Partnership declared a cash distribution for the three months ended September 30, 2018, of $0.6675 per unit, totaling $17.2 million (including a $2.1 million IDR distribution). Such distributions are to be paid on November 13, 2018, to unitholders of record on November 6, 2018.

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

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q (“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, 2017, as filed with the U.S. Securities and Exchange Commission (“SEC”) on March 14, 2018 (the “2017 Annual Report”), in Part I, Item 1A “Risk Factors”, in Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations”, and in Part II, Item 7A “Quantitative and Qualitative Disclosures About Market Risk”. In light of these risks, uncertainties and assumptions, the forward-looking events discussed in this Quarterly Report may not occur.

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

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Overview

We are a Delaware limited partnership formed in June 2011 by Sprague Holdings and our General Partner. We engage in the purchase, storage, distribution and sale of refined products and natural gas, and provide storage and handling services for a broad range of materials. Our limited partnership units representing limited partner interests are listed on the New York Stock Exchange ("NYSE") under the ticker symbol “SRLP". As used in this Quarterly Report, unless otherwise indicated, "Sprague",“we,” “us,” “our” mean Sprague Resources LP and, where the context requires, includes our subsidiaries.

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 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. Furthermore, we 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 15,000 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, clay slurry, salt, gypsum, crude oil, residual fuel oil, coal, petroleum coke, caustic soda, tallow, pulp and heavy equipment. Historically, a majority of our materials handling activity has generated qualified income.

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

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

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As of September 30, 2018, 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.

2017 Acquisitions

Coen Energy Acquisition

On October 1, 2017, we purchased the membership interests of Coen Energy, LLC and Coen Transport, LLC as well as assets consisting of four bulk plants and underlying real estate (collectively, “Coen Energy”). Coen Energy, located in Washington, PA, provides energy products to commercial and residential customers located in Pennsylvania, Ohio and West Virginia. The Coen Energy business also provides fuel and delivery services to customers that are engaged in Marcellus and Utica shale drilling operations. The Coen Energy business is supported by four in-land bulk plants, two throughput locations, approximately 100 delivery vehicles and approximately 250 employees as of December 31, 2017. Initial consideration paid was $35.3 million in cash, not including the purchase of inventory and other adjustments, which was financed with borrowings under our credit facility. Contingent consideration of up to $12 million is payable based on achieving certain economic performance measures during the three year period ending September 30, 2020.

Carbo Terminals Acquisition

On April 18, 2017, we acquired substantially all of the assets of Carbo Industries, Inc. and certain of its affiliates (together “Carbo”) by purchasing Carbo's Inwood and Lawrence, New York refined product terminal assets and its associated wholesale distribution business. The fair value of the consideration totaled $72.0 million and consisted of $13.3 million in cash that was financed through borrowings under our credit facility, an obligation to pay $38.2 million over a ten year period (estimated net present value of $27.3 million) and 1,131,551 common units with a fair value at $31.4 million as of April 18, 2017. The Carbo terminals are primarily supplied by pipeline and have a combined gasoline, ethanol and distillate storage capacity of 174,000 barrels.

Capital Terminal Acquisition

On February 10, 2017, we acquired the East Providence, Rhode Island refined product terminal business of Capital Properties Inc. (the “Capital Terminal”) for $22.0 million which we financed with borrowings under our credit facility. The terminal’s distillate storage capacity of 1.0 million barrels had been leased by us since April 2014 and was previously included in our total storage capacity.

In conjunction with this acquisition, we undertook an expansion capital project to convert half of the terminal’s storage capacity to gasoline and ethanol service to support a new ten year fee-for-service gasoline storage and handling agreement with a major East Coast gasoline marketer and another project to optimize distillate storage between this newly acquired terminal and our existing terminal facility in Providence to allow for expanded materials handling capability. Both projects were completed prior to December 31, 2017 at a total cost of approximately $16 million.

Global Natural Gas & Power Acquisition

On February 1, 2017, we purchased the natural gas marketing and electricity brokering business of Global Partners LP ("Global Natural Gas & Power") for $17.3 million, not including the purchase of natural gas inventory, assumption of derivative liabilities and other adjustments. Consideration paid was $16.3 million and was financed with borrowings under our credit facility. The business serves approximately 4,000 commercial, industrial, municipal and institutional customer locations in the Northeast United States with approximately 8 billion cubic feet of natural gas and 1 billion kWh of electricity annually.

L.E. Belcher Terminal Acquisition

On February 1, 2017, we purchased the Springfield, Massachusetts refined product terminal assets of Leonard E. Belcher, Incorporated (“L.E. Belcher”) for approximately $20.0 million in cash, not including the purchase of inventory and other adjustments.  Consideration paid was $20.7 million and was financed with borrowings under our credit facility. The purchase consists of two pipeline-supplied distillate terminals and one distillate storage facility with a combined capacity of 283,000 barrels, as well as L.E. Belcher’s associated wholesale and commercial fuels businesses.

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How Management Evaluates Our Results of Operations

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

Non-GAAP Financial Measures

We present the non-GAAP financial measures EBITDA, adjusted EBITDA and adjusted gross margin in this Quarterly Report as described below. We present the non-GAAP financial measures maintenance capital expenditures and expansion capital expenditures in this Quarterly Report as described below in "Liquidity and Capital Resources - Capital Expenditures".

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, the viability of acquisitions and capital expenditure projects and 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 (loss) before interest, income taxes, depreciation and amortization. We define adjusted EBITDA as EBITDA 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), changes in fair value of contingent consideration, the net impact of biofuel excise tax credits in 2017 and 2013, and commencing in the fourth quarter of 2017, adjusted for the impact of acquisition related expenses.

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

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

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

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

• The viability of acquisitions and capital expenditure projects.

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

The GAAP measure most directly comparable to EBITDA and adjusted EBITDA is net income (loss). EBITDA and adjusted EBITDA should not be considered as an alternative to net income (loss) 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 (loss) and is 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 an evaluative tool may have certain limitations, including:

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

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

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

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• 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

We trade, purchase, store and sell 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, we adjust our 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 (loss). 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 (loss). 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 (loss) and increased by realized commodity derivative gains and losses included in net income (loss), 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 (loss) or operating income (loss) 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.

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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 to see if a month or a year was warmer or cooler than usual. For purposes of evaluating our results of operations, we use heating degree day amounts as reported by the NOAA Regional Climate Center. Prior to April 1, 2018, we reported degree day information utilizing the New England oil home heating region and for comparison purposes we used historical degree day information for the New England oil home heating region over the period of 1981-2011. Commencing April 1, 2018, 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. We made these changes to incorporate more recent average information and to better reflect the geographic locations of our customer base. All degree day information has been revised to conform to this presentation.

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 statement of operations. In contrast, in a declining commodity price market we generally incur hedging gains. GAAP requires us to record those hedging gains in our statement of operations. 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 statement of operations 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 statement of operations. The natural gas transportation assets market value is calculated daily based on the volume and prices at the corresponding pipeline locations. The daily prices are based on trader assessed quotes which represent observable transactions in the market place, with the end-month valuations primarily based on Platts prices where available or adding a location differential to the price assessment of a more liquid location.

As described above, pursuant to GAAP, we value our commodity derivative hedges at the end of each reporting period based on current commodity prices and record hedging gains or losses, as appropriate. Also as described above, and pursuant to GAAP, our refined products and natural gas inventory and natural gas transportation contract rights, to which the commodity derivative hedges relate, are not marked to market for the purpose of recording gains or losses. In measuring our operating performance, we rely on our GAAP financial results, but we also find it useful to adjust those numbers to 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.

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Trends and Factors that Impact our Business

In addition to the other information set forth in this report, please refer to our 2017 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.” For a description of acquisition activity during the periods presented, please read Note 3 "Business Combinations" to our Condensed Consolidated Financial Statements.

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

	Three Months Ended September 30,						Increase/(Decrease)
	2018			2017			$			%
	(in thousands)
Net sales	$	618,455		$	491,393		$	127,062		26	%
Cost of products sold (exclusive of depreciation and amortization)	581,624			456,656			124,968			27	%
Operating expenses	21,047			16,891			4,156			25	%
Selling, general and administrative	16,923			17,559			(636		)	(4	)%
Depreciation and amortization	8,343			6,655			1,688			25	%
Total operating costs and expenses	627,937			497,761			130,176			26	%
Operating (loss) income	(9,482		)	(6,368		)	(3,114		)	49	%
Other income	293			—			293			—	%
Interest income	123			75			48			64	%
Interest expense	(9,073		)	(7,170		)	(1,903		)	27	%
Loss before income taxes	(18,139		)	(13,463		)	(4,676		)	35	%
Income tax provision	(295		)	(853		)	558			(65	)%
Net loss	$	(18,434	)	$	(14,316	)	$	(4,118	)	29	%

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	Nine Months Ended September 30,						Increase/(Decrease)
	2018			2017			$			%
	(in thousands)
Net sales	$	2,691,259		$	1,922,826		$	768,433		40	%
Cost of products sold (exclusive of depreciation and amortization)	2,462,279			1,720,860			741,419			43	%
Operating expenses	66,537			50,624			15,913			31	%
Selling, general and administrative	63,349			63,472			(123		)	—	%
Depreciation and amortization	25,146			19,537			5,609			29	%
Total operating costs and expenses	2,617,311			1,854,493			762,818			41	%
Operating income	73,948			68,333			5,615			8	%
Other income	293			183			110			60	%
Interest income	404			247			157			64	%
Interest expense	(28,369		)	(22,604		)	(5,765		)	26	%
Income before income taxes	46,276			46,159			117			—	%
Income tax provision	(2,984		)	(3,768		)	784			(21	)%
Net income	$	43,292		$	42,391		$	901		2	%

Analysis of Consolidated Operating Results

Net loss was $18.4 million and $14.3 million for the three months ended September 30, 2018 and 2017, respectively and operating loss was $9.5 million and $6.4 million for the three months ended September 30, 2018 and 2017, respectively. Operating results for the three months ended September 30, 2018 and 2017 include unrealized commodity derivative gains and losses with respect to refined products and natural gas inventory, prepaid forward contracts and natural gas transportation contracts of $(9.2) million and $(13.8) million, respectively. Excluding these unrealized items, operating income for the three months ended September 30, 2018 decreased $7.7 million, or 104%, as compared to the three months ended September 30, 2017.

Net income was $43.3 million and $42.4 million for the nine months ended September 30, 2018 and 2017, respectively and operating income was $73.9 million and $68.3 million for the nine months ended September 30, 2018 and 2017, respectively. Operating results for the nine months ended September 30, 2018 and 2017 include unrealized commodity derivative gains and losses with respect to refined products and natural gas inventory, prepaid forward contracts and natural gas transportation contracts of $23.7 million and $22.4 million, respectively. Excluding these unrealized items, operating income for the nine months ended September 30, 2018 increased $4.3 million, or 9%, as compared to the nine months ended September 30, 2017.

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

Reconciliation to Adjusted Gross Margin, EBITDA and Adjusted EBITDA

The following table sets forth a reconciliation of our consolidated operating income (loss) 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.

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	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
	(in thousands)
Reconciliation of Operating Income to Adjusted Gross Margin:
Operating (loss) income	$	(9,482	)	$	(6,368	)	$	73,948		$	68,333
Operating costs and expenses not allocated to operating segments:
Operating expenses	21,047			16,891			66,537			50,624
Selling, general and administrative	16,923			17,559			63,349			63,472
Depreciation and amortization	8,343			6,655			25,146			19,537
Add: unrealized gain (loss) on inventory (1)	3,281			13,673			(19,309		)	(15,374		)
Add: unrealized loss on prepaid forward contracts (2)	—			(667		)	—			(907		)
Add: unrealized gain (loss) on natural gas transportation contracts (3)	5,939			760			(4,413		)	(6,105		)
Total adjusted gross margin (4):	$	46,051		$	48,503		$	205,258		$	179,580
Adjusted Gross Margin by Segment:
Refined products (5)	$	26,646		$	32,014		$	111,652		$	95,307
Natural gas	3,007			3,197			46,010			44,355
Materials handling	14,683			11,395			42,100			34,118
Other operations	1,715			1,897			5,496			5,800
Total adjusted gross margin	$	46,051		$	48,503		$	205,258		$	179,580
Reconciliation of Net Income to Adjusted EBITDA
Net (loss) income	$	(18,434	)	$	(14,316	)	$	43,292		$	42,391
Add/(deduct):
Interest expense, net	8,950			7,095			27,965			22,357
Tax provision	295			853			2,984			3,768
Depreciation and amortization	8,343			6,655			25,146			19,537
EBITDA (4):	$	(846	)	$	287		$	99,387		$	88,053
Add/(deduct):
Unrealized gain (loss) on inventory (1)	3,281			13,673			(19,309		)	(15,374		)
Unrealized (loss) on prepaid forward contracts (2)	—			(667		)	—			(907		)
Unrealized gain (loss) on natural gas transportation contracts (3)	5,939			760			(4,413		)	(6,105		)
Biofuel tax credit (5)	—			—			(4,022		)	—
Acquisition related expenses (6)	30			722			725			1,707
Other adjustments (7)	204			—			595			—
Adjusted EBITDA	$	8,608		$	14,775		$	72,963		$	67,374
Other Data:
Ten Year Average Heating Degree Days (8)	43			43			3,275			3,311
Heating Degree Days (8)	26			33			3,268			3,106
Variance from average heating degree days	(40		)%	(23		)%	—		%	(6		)%
Variance from prior period heating degree days	(21		)%	(8		)%	5		%	1		%

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(1) Inventory is valued at the lower of cost or net realizable value. The adjustment related to unrealized gain (loss) on inventory which is not included in net income (loss), 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 (loss).

(2) The unrealized (loss) on prepaid forward contracts represents our estimate of the change in fair value of the prepaid forward contracts which are not recorded in net income (loss) until the forward contract is settled in the future (i.e., when the commodity is delivered to the customer). As these contracts are prepaid, they do not qualify as derivatives and changes in the fair value are therefore not included in net income (loss). The fair value of the derivatives we use to economically hedge our prepaid forward contracts declines or appreciates in value as the value of the underlying prepaid forward contract appreciates or declines, which creates unrealized hedging (gains) losses that are included in net income (loss)

(3) The unrealized gain (loss) on natural gas transportation contracts represents our estimate of the change in fair value of the natural gas transportation contracts which are not recorded in net (loss) 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 (loss) income.

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

(5) 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 nine months ended September 30, 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.

(6) Beginning in the fourth quarter of 2017, we have excluded the impact of acquisition related expenses from our calculation of adjusted EBITDA. 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. Adjusted EBITDA for prior periods have been revised to conform to this presentation.

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

(8) We use heating degree day amounts as reported by the NOAA Regional Climate Center. Prior to April 1, 2018, we reported degree day information utilizing the New England oil home heating region and for comparison purposes we used historical degree day information for the New England oil home heating region over the period of 1981-2011. Commencing April 1, 2018, we report degree day information for Boston and New York City (weighted equally) with a historical average for the same locations over the previous ten-year period. We made these changes to incorporate more recent average information and to better reflect the geographic locations of our customer base. All degree day amounts in this document have been revised to conform to this presentation.

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Analysis of Operating Segments

Three Months Ended September 30, 2018 compared to Three Months Ended September 30, 2017

	Three Months Ended September 30,				Increase/(Decrease)
	2018		2017		$			%
	(in thousands, except adjusted unit gross margin)
Volumes:
Refined products (gallons)	246,666		251,496		(4,830		)	(2	)%
Natural gas (MMBtus)	10,705		10,963		(258		)	(2	)%
Materials handling (short tons)	735		603		132			22	%
Materials handling (gallons)	137,928		74,214		63,714			86	%
Net Sales:
Refined products	$	551,489	$	425,492	$	125,997		30	%
Natural gas	46,908		49,694		(2,786		)	(6	)%
Materials handling	14,711		11,395		3,316			29	%
Other operations	5,347		4,812		535			11	%
Total net sales	$	618,455	$	491,393	$	127,062		26	%
Adjusted Gross Margin:
Refined products	$	26,646	$	32,014	$	(5,368	)	(17	)%
Natural gas	3,007		3,197		(190		)	(6	)%
Materials handling	14,683		11,395		3,288			29	%
Other operations	1,715		1,897		(182		)	(10	)%
Total adjusted gross margin	$	46,051	$	48,503	$	(2,452	)	(5	)%
Adjusted Unit Gross Margin:
Refined products	$	0.108	$	0.127	$	(0.019	)	(15	)%
Natural gas	$	0.281	$	0.292	$	(0.011	)	(4	)%

Refined Products

Refined products net sales increased $126.0 million, or 30%, compared to the same period last year, with sales prices 32% higher due to the increased refined products price environment. The 2% decline in volume was driven primarily by lower heavy fuel oil and bunker sales at Kildair Services ULC ("Kildair") as well as their shift from marketing of asphalt to materials handling in March 2018. These decreases were significantly offset by the incremental volume from the Coen Energy acquisition completed in October 2017. Distillate volumes increased, principally due to the incremental Coen Energy sales, with gasoline volumes also higher.

Refined products adjusted gross margin decreased $5.4 million, or 17%, compared to the same period last year. The decrease in adjusted gross margin was primarily due to lower Kildair results due to a combination of the shift of asphalt margin from refined products to materials handling as well as a reduction in heavy fuel oil and bunker sales. A less attractive distillate market to purchase and store inventory also contributed to the lower adjusted unit margins. The incremental adjusted gross margin contribution from the Coen Energy acquisition partially offset the other reductions.

The Partnership is expecting weaker results than previously anticipated in our refined products business for 2018. Specifically, we expect that the convergence of heating oil sulfur specifications and the distillate market structure will limit blending and basis gain opportunities.

Natural Gas

Natural gas net sales declined $2.8 million, or 6%, compared to the same period last year due to a combination of a 3% 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 some higher volume accounts.

Natural gas adjusted gross margin decreased $0.2 million, or 6%, compared to the same period last year, as a result of lower adjusted unit gross margin as well as a volume decrease. The decline in adjusted unit gross margin was impacted by increased competitive intensity in some of our core markets.

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Materials Handling

Materials handling net sales and adjusted gross margin both increased approximately $3.3 million, or 29%, compared to the same period last year. Incremental revenue at Kildair was the primary factor due to the asphalt materials handling agreement that began in March 2018. Materials handling results also benefited from new asphalt handling agreements at two other Sprague terminals as well as incremental structural steel activity and timing difference of dry bulk materials deliveries.

Other Operations

Net sales from other operations increased $0.5 million, or 11%, as a result of the higher coal price environment compared to the same period last year. Adjusted gross margin decreased $0.2 million.

Nine Months Ended September 30, 2018 compared to Nine Months Ended September 30, 2017

	Nine Months Ended September 30,				Increase/(Decrease)
	2018		2017		$			%
	(in thousands, except adjusted unit gross margin)
Volumes:
Refined products (gallons)	1,127,154		994,518		132,636			13	%
Natural gas (MMBtus)	43,287		44,677		(1,390		)	(3	)%
Materials handling (short tons)	2,105		1,879		226			12	%
Materials handling (gallons)	335,538		301,896		33,642			11	%
Net Sales:
Refined products	$	2,396,374	$	1,638,066	$	758,308		46	%
Natural gas	235,263		235,068		195			0	%
Materials handling	42,077		34,118		7,959			23	%
Other operations	17,545		15,574		1,971			13	%
Total net sales	$	2,691,259	$	1,922,826	$	768,433		40	%
Adjusted Gross Margin:
Refined products	$	111,652	$	95,307	$	16,345		17	%
Natural gas	46,010		44,355		1,655			4	%
Materials handling	42,100		34,118		7,982			23	%
Other operations	5,496		5,800		(304		)	(5	)%
Total adjusted gross margin	$	205,258	$	179,580	$	25,678		14	%
Adjusted Unit Gross Margin:
Refined products	$	0.099	$	0.096	$	0.003		3	%
Natural gas	$	1.063	$	0.993	$	0.070		7	%

Refined Products

Refined products net sales increased $758.3 million, or 46%, compared to the same period last year, due to a combination of higher prices and volume. The 29% higher sales prices reflect the substantial increase in the refined products price environment compared to the same period last year. The 13% increase in volume was driven principally by distillates, including the contributions from the Coen Energy acquisition completed in October 2017 and the April 2017 Carbo acquisition. Distillate volume was also higher for discretionary sales, in particular early in the year when a period of severe weather conditions led to competitor supply outages. In addition, heavy oil sales were higher than last year at Sprague's U. S. operations, with the colder weather early in the year a contributing factor.

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Refined products adjusted gross margin increased $16.3 million, or 17%, compared to the same period last year. This gain was primarily due to a 13% increase in volume as discussed above, with the 3% higher adjusted unit gross margin also a factor. Key factors contributing to the higher adjusted unit gross margin included the aforementioned competitor supply outages as well as the retroactive reinstatement of the excise tax credit program on February 9, 2018. This program applies to certain biofuel blending activities and the reinstatement led to us recording an excise tax credit of $4.0 million during the nine months ended September 30, 2018 related to 2017 blending activities. These adjusted gross margin gains coupled with the incremental margin from the Coen Energy acquisition more than offset the less attractive market structure to purchase and store inventory.

Natural Gas

Natural gas net sales increased slightly by $0.2 million, compared to the same period last year. Sales volumes were 3% lower than the same period last year due to the loss of some higher volume accounts as well as increased competitive intensity in some markets which was more than offset by higher prices. This decline in volume was mitigated somewhat by the inclusion of nine months of activity associated with customers acquired via the Global acquisition as compared to eight months last year.

Natural gas adjusted gross margin increased by $1.7 million, or 4%, compared to the same period last year, as a result of the 7% higher adjusted unit gross margin. The increase in adjusted unit gross margin was primarily a result of improved performance achieved during the severe weather conditions in the early part of 2018 as well as the loss of some higher volume, lower unit margin accounts.

Materials Handling

Materials handling net sales and adjusted gross margin both increased $8.0 million, or approximately 23%, compared to the same period last year. The primary factor was increased asphalt handling revenues as a result of new agreements at our Kildair facility as well as two other Sprague terminals.  Materials handling adjusted gross margin also benefited from increased heavy lift activity due to the handling of structural steel components and timing differences of dry bulk materials deliveries.

Other Operations

Net sales from other operations increased by $2.0 million, or 13%, as a result of the higher coal price environment compared to the same period last year. Adjusted gross margin was $0.3 million lower.

Operating Costs and Expenses

Three Months Ended September 30, 2018 compared to Three Months Ended September 30, 2017

	Three Months Ended September 30,				Increase/(Decrease)
	2018		2017		$			%
	(in thousands)
Operating expenses	$	21,047	$	16,891	$	4,156		25%
Selling, general and administrative	$	16,923	$	17,559	$	(636	)	(4)%
Depreciation and amortization	$	8,343	$	6,655	$	1,688		25%
Interest expense, net	$	8,950	$	7,095	$	1,855		26%

Operating Expenses. Operating expenses increased $4.2 million, or 25%, compared to the same period last year, reflecting $3.7 million of operating expenses related to the Coen Energy acquisition and $0.4 million of higher stockpile expenses.

Selling, General and Administrative Expenses. SG&A expenses decreased $0.6 million, or 4%, compared to the same period last year. This decline was driven by a $1.0 million decrease in incentive compensation and lower acquisition related expenses of $0.7 million partially offset by an increase of $0.9 million connected to our Coen Energy acquisition.

Depreciation and Amortization. Depreciation and amortization increased $1.7 million, or 25%, compared to the same period last year, primarily as a result of the Coen Energy acquisition.

Interest Expense, net. Interest expense, net increased $1.9 million, or 26%, compared to the same period last year primarily relating to increased borrowings coupled with increases in interest rates and a step-up into a higher pricing tier within the acquisition facility of our Credit Agreement.

35

Nine Months Ended September 30, 2018 compared to Nine Months Ended September 30, 2017

	Nine Months Ended September 30,				Increase/(Decrease)
	2018		2017		$			%
	(in thousands)
Operating expenses	$	66,537	$	50,624	$	15,913		31%
Selling, general and administrative	$	63,349	$	63,472	$	(123	)	0%
Depreciation and amortization	$	25,146	$	19,537	$	5,609		29%
Interest expense, net	$	27,965	$	22,357	$	5,608		25%

Operating Expenses. Operating expenses increased $15.9 million, or 31%, compared to the same period last year, reflecting $13.1 million of operating expenses related to the 2017 acquisitions, $1.2 million of increased employee related costs and $1.6 million of boiler fuel, insurance, legal and utility expenses predominantly attributable to activity at our terminals.

Selling, General and Administrative Expenses. SG&A expenses decreased $0.1 million, compared to the same period last year. This decline was driven by a $4.2 million decrease in incentive compensation and lower acquisition related costs of $1.0 million partially offset by an increase in expenses of $3.1 million connected to our Coen Energy acquisition and $1.8 million of increased employee related costs.

Depreciation and Amortization. Depreciation and amortization increased $5.6 million, or 29%, compared to the same period last year, primarily as a result of acquisitions during 2017.

Interest Expense, net. Interest expense, net increased $5.6 million, or 25%, compared to the same period last year primarily relating to increased borrowings coupled with increases in interest rates and a step-up into a higher pricing tier within the acquisition facility of our Credit Agreement and to a lesser extent increased working capital requirements.

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 September 30, 2018, we had working capital of $226.2 million.

As of September 30, 2018, the undrawn borrowing capacity under the working capital facilities of our Credit Agreement was $124.7 million and the undrawn borrowing capacity under the acquisition facility was $170.9 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 nine months ended September 30, 2018, the amount drawn under the working capital facilities of our Credit Agreement fluctuated from a low of $175.0 million to a high of $395.6 million.

We believe that we have sufficient liquid assets, cash flow from operations and borrowing capacity under our Credit Agreement to meet our financial commitments, debt service obligations, contingencies and anticipated capital expenditures. However, we are subject to business and operational risks that could adversely affect our cash flow. A material decrease in our cash flow would likely have an adverse effect on our ability to meet our financial commitments and debt service obligations.

Credit Agreement

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.

36

As of September 30, 2018, 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%.

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 September 30, 2018.

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.

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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)
Nine Months Ended September 30,
2018	$	5,754	$	7,580	$	13,334
2017(1)	$	23,422	$	7,884	$	31,306

(1) Excludes approximately $8.5 million of assets acquired in 2017 that were previously leased by the Partnership.

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

	Nine Months Ended September 30,
	2018			2017
	(in thousands)
Net cash provided by operating activities	$	191,302		$	126,891
Net cash used in investing activities	$	(12,956	)	$	(111,047	)
Net cash used in financing activities	$	(166,571	)	$	(15,453	)

Operating Activities

Net cash provided by operating activities for the nine months ended September 30, 2018 was $191.3 million and was primarily driven by cash inflows as a result of a decrease of $124.9 million in accounts receivable due to a seasonal reduction in sales volume, a decrease of $123.9 million in inventories due to a reduction in inventory requirements, and $43.3 million in net income. These inflows were offset by cash outflows as a result of a reduction of $114.8 million in accounts payable and accrued liabilities primarily relating to the timing of invoice payments for product purchases and $29.6 million representing the net impact in our derivative instruments as a result of changes in commodity prices during the period and seasonal reduction.

Net cash provided by operating activities for the nine months ended September 30, 2017 was $126.9 million and was primarily driven by cash inflows as a result of a decrease of $73.9 million in inventories due to a reduction in inventory requirements, a decrease of $77.7 million in accounts receivable due to a seasonal reduction in sales volume, and $42.4 million in net income. These inflows were offset by cash outflows as a result of a reduction of $80.5 million in accounts payable and accrued liabilities primarily relating to the timing of invoice payments for product purchases and an increase of $19.8 million in our derivative instruments as a result of changes in commodity prices during the period.

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Investing Activities

Net cash used in investing activities for the nine months ended September 30, 2018 was $13.0 million of which $5.8 million related to expansion capital expenditures and $7.6 million related to maintenance capital expenditure projects across our terminal system.

Net cash used in investing activities for the nine months ended September 30, 2017 was $111.0 million of which $72.2 million related to the purchase of four acquisitions, $23.4 million related to expansion capital expenditures, $7.9 million related to maintenance capital expenditure projects across our terminal system and $8.5 million related to a purchase of real estate previously leased by us at our Portland Merrill terminal.

Financing Activities

Net cash used in financing activities for the nine months ended September 30, 2018 was $166.6 million, and primarily resulted from $109.5 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 $51.4 million.

Net cash used in financing activities for the nine months ended September 30, 2017 was $15.5 million, and primarily resulted from distributions of $42.4 million partially offset by $35.0 million of borrowings under our Credit Agreement acquisition line to fund the acquisitions.

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 nine months ended September 30, 2018 and 2017.

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: asset valuations, the fair value of derivative assets and liabilities, environmental and legal obligations.

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 2017 Annual Report and as updated in Note 2 to this Quarterly Report as it relates to revenue recognition. 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.

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Item 3. Quantitative and Qualitative Disclosures about Market Risk

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

Commodity Price Risk

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

As indicated in the table below, we primarily use futures contracts to hedge light oil transactions and swaps contracts for 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 contract that trades on the Chicago Board of Trade, or CBOT, to hedge ethanol that is used for blending into our gasoline. This ethanol contract is based on Chicago delivery. 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 September 30,						Nine Months Ended September 30,
	(in thousands)
	2018			2017			2018			2017
Refined products contracts	$	1,087		$	(17,281	)	$	10,063		$	27,637
Natural gas contracts	(6,244		)	(908		)	(9,204		)	13,850
Total	$	(5,157	)	$	(18,189	)	$	859		$	41,487

Substantially all of our commodity derivative contracts outstanding as of September 30, 2018 will settle prior to March 31, 2020.

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Interest Rate Risk

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

Our interest rate swap agreements outstanding as of September 30, 2018 were as follows (in thousands):

Beginning	Ending	Notional Amount
January 2018	January 2019	$	275,000
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 September 30, 2018 we hedged approximately 44% 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 September 30, 2018, we estimate that if short-term interest rates increased or decreased 100 basis points, our interest expense would have increased approximately $3.8 million and decreased approximately $3.8 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 September 30, 2018:

	As of September 30, 2018
	Fair Value Measurement		Active Markets Level 1		Observable Inputs Level 2		Unobservable Inputs Level 3
	(in thousands)
Derivative assets:
Commodity fixed forwards	$	14,209	$	—	$	14,209	$	—
Futures, swaps and options	42,571		42,566		5		—
Commodity derivatives	56,780		42,566		14,214		—
Interest rate swaps	5,993		—		5,993		—
Other	14		—		14		—
Total derivative assets	$	62,787	$	42,566	$	20,221	$	—
Derivative liabilities:
Commodity fixed forwards	$	42,175	$	—	$	42,175	$	—
Futures, swaps and options	37,862		37,858		4		—
Commodity derivatives	80,037		37,858		42,179		—
Interest rate swaps	48		—		48		—
Total derivative liabilities	$	80,085	$	37,858	$	42,227	$	—

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Market and Credit Risk

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

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

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

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

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

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Item 4. Controls and Procedures

Disclosure Controls and Procedures

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

As of September 30, 2018, the Partnership carried out an evaluation, under the supervision and with the participation of management (including the President and Chief Executive Officer and the Senior Vice President, Chief Operating 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 Senior Vice President, Chief Operating Officer and Chief Financial Officer concluded that the Partnership's disclosure controls and procedures were effective as of September 30, 2018.

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 September 30, 2018 that have materially affected, or are reasonably likely to materially affect, the Partnership’s internal control over financial reporting.

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PART II—OTHER INFORMATION

Item 1. Legal Proceedings

Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not a party to any litigation or governmental or other proceeding that we believe will have a material adverse impact on our consolidated financial condition or results of operations.

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 2017 Annual Report, which could materially affect our business, financial condition or future results.

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

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

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Item 6. Exhibits

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

EXHIBIT INDEX

Exhibit No.	Description
2.1***	Purchase and Sale Agreement, dated September 18, 2017, by and among Sprague Operating Resources LLC, Coen Oil Company, LLC, Coen Markets, Inc., and The Thomaston Land Company, LLC (incorporated by reference to Exhibit 2.1 of Sprague Resources LP's Current Report on Form 8-K filed September 19, 2017 (File No. 001-36137)).
2.2***	First Amendment dated April 18, 2017 to Asset Purchase Agreement by and among Sprague Operating Resources LLC, Carbo Industries, Inc. and Carbo Realty, LLC (incorporated by reference to Exhibit 2.1 of Sprague Resources LP’s Current Report on Form 8-K filed April 19, 2017 (File No. 001-36137)).
2.3***	Asset Purchase Agreement, dated March 13, 2017, by and among Carbo Industries, Inc., Carbo Realty, LLC, and Paul Hochhauser and Sprague Operating Resources, LLC (incorporated by reference to Exhibit 2.1 of Sprague Resources LP’s Current Report on Form 8-K filed March 16, 2017 (File No. 001-36137)).
2.4***	Asset Purchase Agreement, dated January 24, 2017, by and among Capital Properties, Inc., Dunellen, LLC, Capital Terminal Company and Sprague Operating Resources LLC (incorporated by reference to Exhibit 2.1 of Sprague Resources LP’s Current Report on Form 8-K filed January 25, 2017 (File No. 001-36137)).
2.5***	Terminal and Wholesale Fuels Asset Purchase Agreement, dated January 23, 2017, by and between Leonard E. Belcher Incorporated and Sprague Operating Resources LLC (incorporated by reference to Exhibit 2.1 of Sprague Resources LP’s Current Report on Form 8-K filed January 23, 2017 (File No. 001-36137)).
2.6***	Asset Purchase Agreement, dated December 30, 2016, by and among Sprague Operating Resources LLC, Sprague Energy Inc., Sprague Resources LP, Global Montello Group Corp., Global Energy Marketing LLC and Global Partners LP (incorporated by reference to Exhibit 2.1 of Sprague Resources LP’s Current Report on Form 8-K filed January 3, 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.

45

EXHIBIT INDEX (Continued)

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.

46

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: November 7, 2018		/s/ Gary A. Rinaldi
		Gary A. Rinaldi Senior Vice President, Chief Operating Officer and Chief Financial Officer (on behalf of the registrant, and in his capacity as Principal Financial Officer)

47

EX-31.1

Exhibit 31.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, David C. Glendon, certify that:

1.	I have reviewed this quarterly report on Form 10-Q of Sprague Resources LP;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
	a.	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
	b.	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
	c.	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	d.	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
	a.	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
	b.	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 7, 2018

/s/ DAVID C. GLENDON

David C. Glendon

President and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, Gary A. Rinaldi, certify that:

1.	I have reviewed this quarterly report on Form 10-Q of Sprague Resources LP;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
	a.	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
	b.	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
	c.	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	d.	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
	a.	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
	b.	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 7, 2018

/s/ GARY A. RINALDI

Gary A. Rinaldi

Senior Vice President, Chief Operating Officer

and Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with this Quarterly Report of Sprague Resources LP (the “Partnership”) on Form 10-Q for the three months ended September 30, 2018, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, David C. Glendon, President and Chief Executive Officer of the general partner of the Partnership, certify pursuant to 18 U.S.C. §1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:

1.	The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as amended; and
2.	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

Date: November 7, 2018

/s/ DAVID C. GLENDON

David C. Glendon

President and Chief Executive Officer

(Principal Executive Officer)

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with this Quarterly Report of Sprague Resources LP (the “Partnership”) on Form 10-Q for the three months ended September 30, 2018, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Gary A. Rinaldi, Senior Vice President, Chief Operating Officer and Chief Financial Officer of the general partner of the Partnership, certify pursuant to 18 U.S.C. §1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:

1.	The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as amended; and
2.	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

Date: November 7, 2018

/s/ GARY A. RINALDI

Gary A. Rinaldi

Senior Vice President, Chief Operating Officer and

Chief Financial Officer

(Principal Financial Officer)

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Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2018	Nov. 01, 2018
Document And Entity Information [Abstract]
Entity Registrant Name	Sprague Resources LP
Trading Symbol	SRLP
Entity Central Index Key	0001525287
Current Fiscal Year End Date	--12-31
Entity Filer Category	Accelerated Filer
Document Type	10-Q
Document Period End Date	Sep. 30, 2018
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	Q3
Amendment Flag	false
Entity Common Stock, Shares Outstanding		22,733,977
Entity Emerging Growth Company	false
Entity Small Business	false

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Condensed Consolidated Balance Sheets - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Current assets:
Cash and cash equivalents	$ 18,621	$ 6,815
Accounts receivable, net	190,770	316,613
Inventories	211,946	335,859
Fair value of derivative assets	50,466	107,254
Other current assets	19,754	39,946
Total current assets	491,557	806,487
Fair value of derivative assets, long-term	12,321	7,493
Property, plant and equipment, net	350,145	350,059
Intangibles, net	62,754	71,891
Other assets, net	9,496	12,018
Goodwill	115,037	115,037
Total assets	1,041,310	1,362,985
Current liabilities:
Accounts payable	94,431	205,105
Accrued liabilities	46,310	49,038
Fair value of derivative liabilities	71,712	156,763
Due to General Partner	5,441	11,228
Current portion of working capital facilities	40,545	275,613
Current portion of other obligations	6,914	6,476
Total current liabilities	265,353	704,223
Commitments and contingencies
Working capital facilities - less current portion / acquisition facility	574,955	449,737
Fair value of derivative liabilities, long-term	8,373	8,265
Other obligations - less current portion	48,567	49,625
Due to General Partner	2,016	1,678
Deferred income taxes	17,678	17,623
Total liabilities	916,942	1,231,151
Unitholders’ equity:
Accumulated other comprehensive loss, net of tax	(5,638)	(8,870)
Total unitholders’ equity	124,368	131,834
Total liabilities and unitholders’ equity	1,041,310	1,362,985
Common Unitholders - Public
Unitholders’ equity:
Unitholders - units issued	188,038	193,977
Common Unitholders - Affiliated
Unitholders’ equity:
Unitholders - units issued	(58,032)	(53,273)
Working capital facilities
Current liabilities:
Working capital facilities - less current portion / acquisition facility	195,855	66,237
Acquisition facility
Current liabilities:
Working capital facilities - less current portion / acquisition facility	$ 379,100	$ 383,500

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Condensed Consolidated Balance Sheets (Parenthetical) - shares	Sep. 30, 2018	Dec. 31, 2017
Common Unitholders - Public
Units, issued (in shares)	10,620,936	10,446,539
Units, outstanding (in shares)	10,620,936	10,446,539
Common Unitholders - Affiliated
Units, issued (in shares)	12,106,348	12,106,348
Units, outstanding (in shares)	12,106,348	12,106,348

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Unaudited Condensed Consolidated Statements of Operations - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Net sales	$ 618,455	$ 491,393	$ 2,691,259	$ 1,922,826
Cost of products sold (exclusive of depreciation and amortization)	581,624	456,656	2,462,279	1,720,860
Operating expenses	21,047	16,891	66,537	50,624
Selling, general and administrative	16,923	17,559	63,349	63,472
Depreciation and amortization	8,343	6,655	25,146	19,537
Total operating costs and expenses	627,937	497,761	2,617,311	1,854,493
Operating (loss) income	(9,482)	(6,368)	73,948	68,333
Other income	293	0	293	183
Interest income	123	75	404	247
Interest expense	(9,073)	(7,170)	(28,369)	(22,604)
(Loss) income before income taxes	(18,139)	(13,463)	46,276	46,159
Income tax provision	(295)	(853)	(2,984)	(3,768)
Net (loss) income	(18,434)	(14,316)	43,292	42,391
Incentive distributions declared	(2,055)	(1,024)	(5,824)	(2,620)
Limited partners’ interest in net (loss) income	$ (20,489)	$ (15,340)	$ 37,468	$ 39,771
Units used to compute net (loss) income per limited partner unit:
Common - basic units (in shares)	22,727,284	22,543,527	22,726,645	22,093,578
Common - diluted units (in shares)	22,727,284	22,543,527	22,766,725	22,368,432
Distribution declared per unit (in dollars per share)	$ 0.6675	$ 0.6225	$ 1.9875	$ 1.8225
Common Unitholders - Affiliated
Net (loss) income per limited partner unit:
Common - basic (in dollars per share)	(0.90)	(0.68)	1.65	1.80
Common - diluted (in dollars per share)	$ (0.90)	$ (0.68)	$ 1.65	$ 1.78

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Unaudited Condensed Consolidated Statements of Comprehensive Income (Loss) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Statement of Comprehensive Income [Abstract]
Net (loss) income	$ (18,434)	$ (14,316)	$ 43,292	$ 42,391
Unrealized gain on interest rate swaps
Net gain arising in the period	1,503	410	4,734	699
Reclassification adjustment related to gain realized in income	(619)	(129)	(1,398)	(13)
Net change in unrealized gain on interest rate swaps	884	281	3,336	686
Tax effect	(7)	(3)	(25)	(10)
Unrealized (loss) gain on interest rate swaps, Total	877	278	3,311	676
Foreign currency translation adjustment	48	139	(79)	249
Other comprehensive income	925	417	3,232	925
Comprehensive (loss) income	$ (17,509)	$ (13,899)	$ 46,524	$ 43,316

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Unaudited Condensed Consolidated Statements of Unitholders' Equity (Deficit) - USD ($) $ in Thousands	Total	Common- Public	Common- Sprague Holdings	Subordinated- Sprague Holdings	Incentive Distribution Rights	Accumulated Other Comprehensive Loss
Beginning balance at Dec. 31, 2016	$ 125,437	$ 175,314	$ (4,518)	$ (34,576)	$ 0	$ (10,783)
Increase (Decrease) in Partners' Capital [Roll Forward]
Conversion of subordinated units to common units			(40,393)	40,393
Net income	29,497	11,955	14,324		3,218
Other comprehensive income	1,913					1,913
Unit-based compensation	2,274	1,034	1,240
Distributions paid	(57,472)	(25,198)	(23,239)	(5,817)	(3,218)
Common units issued related to Carbo acquisition	31,401	31,401
Common units issued with annual bonus	371	161	210
Units withheld for employee tax obligations	(1,587)	(690)	(897)
Ending balance at Dec. 31, 2017	131,834	193,977	(53,273)	0	0	(8,870)
Increase (Decrease) in Partners' Capital [Roll Forward]
Net income	43,292	17,828	20,323		5,141
Other comprehensive income	3,232					3,232
Unit-based compensation	(91)	(43)	(48)
Distributions paid	(51,391)	(22,552)	(23,698)	0	(5,141)
Units withheld for employee tax obligations	(2,508)	(1,172)	(1,336)
Ending balance at Sep. 30, 2018	$ 124,368	$ 188,038	$ (58,032)	$ 0	$ 0	$ (5,638)

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Unaudited Condensed Consolidated Statements of Cash Flows - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Cash flows from operating activities
Net income	$ 43,292	$ 42,391
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization (includes amortization of deferred debt issuance costs)	27,802	23,881
Gain on sale of assets and insurance recoveries	(266)	(101)
Changes in fair value of contingent consideration	521	0
Provision for doubtful accounts	942	(251)
Non-cash unit-based compensation	(91)	1,688
Other	75	0
Deferred income taxes	(49)	953
Changes in assets and liabilities:
Accounts receivable	124,901	77,660
Inventories	123,913	73,944
Other assets	20,185	14,040
Fair value of commodity derivative instruments	(29,649)	(19,813)
Due to General Partner and affiliates	(5,449)	(6,977)
Accounts payable, accrued liabilities and other	(114,825)	(80,524)
Net cash provided by operating activities	191,302	126,891
Cash flows from investing activities
Purchases of property, plant and equipment	(13,333)	(39,774)
Business acquisitions	0	(72,184)
Proceeds from property insurance settlement and sale of assets	377	911
Net cash used in investing activities	(12,956)	(111,047)
Cash flows from financing activities
Net (payments) borrowings under credit agreements	(109,454)	35,003
Payments on capital leases, term debt, and other obligations	(3,019)	(1,977)
Debt issue costs	(182)	(4,483)
Distributions to unitholders	(51,391)	(42,409)
Foreign exchange on capital lease obligations	(17)	0
Repurchased units withheld for employee tax obligations	(2,508)	(1,587)
Net cash used in financing activities	(166,571)	(15,453)
Effect of exchange rate changes on cash balances held in foreign currencies	31	121
Net change in cash and cash equivalents	11,806	512
Cash and cash equivalents, beginning of period	6,815	2,682
Cash and cash equivalents, end of period	18,621	3,194
Supplemental disclosure of cash flow information
Cash paid for interest	25,443	18,293
Cash paid for taxes	3,497	1,601
Non-cash consideration related to acquisition:
Common units issued - Carbo	0	31,401
Deferred consideration obligation - Carbo	$ 0	$ 27,284

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Description of Business and Summary of Significant Accounting Policies

9 Months Ended

Sep. 30, 2018

Accounting Policies [Abstract]

Description of Business and Summary of Significant Accounting Policies

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. Unless the context otherwise requires, 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.

• 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 our revenue activities within these business segments.

Prior to February 16, 2017, Sprague Holdings owned, directly or indirectly, all of the Partnership’s subordinated units. The principal difference between the Partnership’s common units and subordinated units is that during the subordination period, the common units had the right to receive a minimum quarterly distribution of $0.4125 per common unit, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of cash from distributable cash flow could be made on the subordinated units. On February 16, 2017, based upon meeting certain distribution and performance tests provided in the Partnership's partnership agreement, all 10,071,970 subordinated units outstanding converted to common units on a one-for-one basis.

As of September 30, 2018, 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 Note13 "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, 2017 as filed with the SEC on March 14, 2018 (the “2017 Annual Report”).

The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities in the balance sheet and the reported net sales and expenses in the income statement. Actual results could differ from those estimates. Among the estimates made by management are asset and liability valuations as part of an acquisition, 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 September 30, 2018 and December 31, 2017, the consolidated results of operations for the three and nine months ended September 30, 2018 and 2017, and the consolidated cash flows for the nine months ended September 30, 2018 and 2017. 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 2017 Annual Report and are the same as are used in preparing these unaudited interim Condensed Consolidated Financial Statements except for the adoption of ASU 2014-09, Revenue from Contracts with Customers (Topic 606) which the Partnership adopted as of January 1, 2018.The adoption of Topic 606 is discussed further in Recent Accounting Pronouncements below as well as in Note 2 "Revenue".

Recent Accounting Pronouncements

In July 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2017-12, Derivatives and Hedging: 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 Partnership is currently evaluating the impact of this new standard on the 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 January 2017, the FASB issued ASU 2017-01 Business Combinations (Topic 805), whichclarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. This ASU is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. The Partnership will follow this new guidance for transactions entered into after December 31, 2017.

In August 2016, the FASB issued ASU 2016-15 Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments, which addresses eight specific cash flow issues with the objective of reducing diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows under Topic 230, Statement of Cash Flows, and other Topics. This ASU is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years and is to be applied retrospectively to all periods presented. The adoption of this guidance in 2018 did not have an impact on the Partnership's consolidated statements of cash flows.

In February 2016, the FASB issued ASU 2016-02 Leases (Topic 842), which, among other things, requires lessees to recognize at the commencement date of a lease a liability, which is a lessee's 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. This ASU is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. In June 2018, the FASB issued ASU 2018-11 that introduced a transition option, that the Partnership intends to adopt, that will allow the new standard to be adopted without revising comparative period reporting or disclosures. The Partnership has started the process of gathering and analyzing its lease contracts and is in the process of evaluating changes to business processes, systems and controls needed to support recognition and disclosure under this new standard. While the adoption of this new standard is expected to result in an increase to reported assets and liabilities, the Partnership has not yet determined the full impact that the adoption of ASU 2016-02 will have on its consolidated financial statements.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606), which revises the

principles of revenue recognition from one based on the transfer of risks and rewards to when a customer obtains control of a

good or service. The FASB issued several ASUs after ASU 2014-09 to clarify implementation guidance but did not change the core principle of the guidance in Topic 606. These ASUs are effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. The adoption of this standard in 2018 did not have an impact on the Partnership's consolidated financial statements nor result in significant changes to business processes, systems, or internal controls.

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Revenue

9 Months Ended

Sep. 30, 2018

Revenue from Contract with Customer [Abstract]

Revenue

Revenue

Accounting Policies

Revenue is recognized when performance obligations under the terms of a contract with a customer are satisfied. The majority of the Partnership’s revenue is generated from refined products and natural gas contracts that have a single performance obligation which is the delivery of the related energy product. Accordingly, the Partnership recognizes revenue for refined products and natural gas when title and risk of loss have been transferred to the customer which is generally at the time of shipment or delivery of products. Revenue for the Partnership’s materials handling segment is recorded on a straight-line basis under leasing arrangements or as services are performed.

Revenue is measured as the amount of consideration the Partnership expects to receive in exchange for transferring products or providing services and is generally based upon a negotiated index, formula, list or fixed price. An allowance for doubtful accounts is recorded to reflect an estimate of the ultimate realization of the Partnership's accounts receivable and includes an assessment of the customers’ creditworthiness and the probability of collection. Estimated discounts are included in the transaction price of the contracts with customers as a reduction to net sales. The Partnership sells its products or provides its services directly to commercial customers and wholesale distributors generally under agreements with payment terms typically less than 30 days.

The Partnership has elected to account for shipping and handling as activities to fulfill the promise to transfer the good. As such, shipping and handling fees billed to customers in a sales transaction are recorded in net sales and shipping and handling costs incurred are recorded in cost of products sold (exclusive of depreciation and amortization). The Partnership has elected to exclude from net sales any value add, sales and other taxes which it collects concurrently with revenue-producing activities. These accounting policy elections are consistent with the way the Partnership historically recorded shipping and handling fees and taxes.

The majority of the Partnership's revenue is derived from contracts (i) with an original expected length of one year or less and (ii) contracts for which it recognizes revenue at the amount in which it has the right to invoice the customer as product is delivered. The Partnership has elected the practical expedient not to disclose the value of remaining performance obligations associated with these types of contracts.

Contract Balances

Contract liabilities primarily relate to advances or deposits received from the Partnership's customers before revenue is recognized. These amounts are included in accrued liabilities and amounted to $7.8 million and $7.7 million as of September 30, 2018 and December 31, 2017, respectively. A substantial portion of the contract liabilities as of December 31, 2017 remains outstanding as of September 30, 2018 as they are primarily deposits. The Partnership does not have any material contract assets as of September 30, 2018 or December 31, 2017.

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. 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 includes the purchase and distribution of coal, certain commercial trucking activities and a heating equipment service business. Revenue from other activities 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 September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
Net sales:
Refined products
Distillates	$	403,186	$	279,381	$	1,890,740	$	1,217,866
Gasoline	88,536		71,971		252,852		208,669
Heavy fuel oil and asphalt	59,767		74,140		252,782		211,531
Total refined products	$	551,489	$	425,492	$	2,396,374	$	1,638,066
Natural gas	46,908		49,694		235,263		235,068
Materials handling	14,711		11,395		42,077		34,118
Other operations	5,347		4,812		17,545		15,574
Net sales	$	618,455	$	491,393	$	2,691,259	$	1,922,826
Net sales by Country:
United States	$	549,477	$	408,897	$	2,485,922	$	1,735,778
Canada	$	68,978	$	82,496	$	205,337	187,048
Net sales	$	618,455	$	491,393	$	2,691,259	$	1,922,826

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Business Combinations

9 Months Ended

Sep. 30, 2018

Business Combinations [Abstract]

Business Combinations

Business Combinations

The Partnership completed five business acquisitions during the year ended December 31, 2017 as described below. Allocations of the purchase price to the assets acquired and liabilities assumed have been made to record, where applicable, inventory, derivative assets and liabilities, natural gas transportation assets and liabilities, property, plant and equipment, identifiable intangible assets such as customer relationships and non-compete agreements as well as goodwill. If the results of these businesses had been included in the consolidated results of the Partnership for the entire three and nine months ended September 30, 2017, unaudited consolidated pro forma net sales would have been $514.0 million and $2,025.0 million, respectively, while the unaudited pro forma net (loss) income for the three months and nine months ended September 30, 2017 would not have been materially different.

The Partnership recognized less than $0.1 million and $0.7 million of acquisition related costs during the three months ended September 30, 2018 and 2017, and $0.7 million and $1.7 million for the nine months ended September 30, 2018 and 2017, respectively, which are included in selling, general and administrative expense.

Year Ended December 31, 2017

Coen Energy

On October 1, 2017, the Partnership purchased the membership interests of Coen Energy, LLC and Coen Transport, LLC as well as assets consisting of four bulk plants and underlying real estate (collectively, “Coen Energy”). Coen Energy, located in Washington, PA, provides energy products to commercial and residential customers located in Pennsylvania, Ohio and West Virginia. The Coen Energy business also provides energy fuel services to customers that are engaged in Marcellus and Utica shale drilling operations. The Coen Energy business is supported by four in-land bulk plants, two throughput locations, approximately 100 delivery vehicles and approximately 250 employees as of December 31, 2017. Initial consideration paid was $35.3 million in cash, not including the purchase of inventory and other adjustments, which was financed with borrowings under the Credit Agreement. Contingent consideration of up to $12.0 million is payable based on achieving certain economic performance measures during the three year period ending September 30, 2020. The operations of Coen Energy have been included in the Partnership's refined products segment since the acquisition date.

The following table summarizes the fair values of the assets acquired and liabilities assumed at the acquisition date:

Inventories	$	567
Other current assets	115
Property, plant and equipment	12,972
Intangibles	18,375
Total identifiable assets acquired	32,029
Other liabilities	(256		)
Net identifiable assets acquired	31,773
Goodwill	13,095
Net assets acquired	$	44,868

The goodwill recognized is primarily attributable to Coen Energy’s reputation in its geographic market area, the in-place workforce and the residual cash flow the Partnership believes that it will be able to generate.

Carbo Terminals    

On April 18, 2017, the Partnership acquired substantially all of the assets of Carbo Industries, Inc. and certain of its affiliates (together “Carbo”) by purchasing Carbo's Inwood and Lawrence, New York refined product terminal assets and its associated wholesale distribution business. The fair value of the consideration totaled $72.0 million and consisted of $13.3 million in cash that was financed through borrowings under the Credit Agreement, an obligation to pay $38.2 million over a ten year period (estimated net present value of $27.3 million) and $31.4 million in unregistered common units. The Carbo terminals have a combined gasoline, ethanol and distillate storage capacity of 174,000 barrels and are supplied primarily by pipeline with the ability to also accept product deliveries by barge and truck. The operations of Carbo are included in the Partnership's refined products segment since the acquisition date.

The following table summarizes the fair values of the assets acquired and liabilities assumed at the acquisition date:

Inventories	$	3,220
Derivative and other current assets	111
Property, plant and equipment	22,995
Intangibles	29,000
Total identifiable assets acquired	55,326
Other liabilities	(188		)
Net identifiable assets acquired	55,138
Goodwill	16,718
Net assets acquired	$	71,856

The goodwill recognized is primarily attributable to Carbo’s reputation in the New York City area, the in-place workforce and the residual cash flow the Partnership believes that it will be able to generate.

Capital Terminal

On February 10, 2017, the Partnership purchased the East Providence, Rhode Island refined product terminal business of Capital Properties Inc. (the “Capital Terminal”). Consideration paid was $22.0 million and was financed with borrowings under the Credit Agreement. The terminal’s distillate storage capacity of 1.0 million barrels had been leased by the Partnership since April 2014 and was previously included in the Partnership’s total storage capacity. The operations of the Capital Terminal are included in the Partnership's refined products segment since the acquisition date.

The following table summarizes the fair values of the assets acquired and liabilities assumed at the acquisition date:

Property, plant and equipment	$	21,960
Accrued liabilities and other, net	(22		)
Net assets acquired	$	21,938

Global Natural Gas & Power

On February 1, 2017, the Partnership purchased the natural gas marketing and electricity brokering business of Global Partners LP ("Global Natural Gas & Power") for $17.3 million, not including the purchase of natural gas inventory, assumption of derivative assets (liabilities) and other adjustments. Consideration paid was $16.3 million and was financed with borrowings under the Credit Agreement. This business markets natural gas and electricity to commercial, industrial, municipal and institutional customer locations in the Northeast United States. The operations of Global Natural Gas & Power are included in the Partnership's natural gas segment since the acquisition date.

    The following table summarizes the fair values of the assets acquired and liabilities assumed at the acquisition date:

Inventory	$	286
Derivative assets	5,873
Natural gas transportation assets	695
Derivative assets long term	1,089
Natural gas transportation assets long term	378
Intangibles	5,046
Total identifiable assets acquired	13,367
Derivative liabilities	(4,865		)
Natural gas transportation liabilities	(465		)
Derivative liabilities long term	(1,214		)
Natural gas transportation liabilities long term	(162		)
Net identifiable assets acquired	6,661
Goodwill	9,592
Net assets acquired	$	16,253

The goodwill recognized is primarily attributable to Global Natural Gas & Power’s reputation in its market regions, the in-place workforce and the residual cash flow the Partnership believes that it will be able to generate.

L.E. Belcher Terminal

On February 1, 2017, the Partnership purchased the Springfield, Massachusetts refined product terminal assets of Leonard E. Belcher, Incorporated (“L.E. Belcher”) for approximately $20.0 million, not including the purchase of inventory, assumption of derivative assets (liabilities) and other adjustments. Consideration paid was $20.7 million and was financed with borrowings under the Credit Agreement. The purchase consists of two pipeline-supplied distillate terminals and one distillate storage facility with a combined capacity of 283,000 barrels, as well as L.E. Belcher’s associated wholesale and commercial fuels businesses. The operations of L.E. Belcher are included in the Partnership's refined products segment since the acquisition date.

The following table summarizes the fair values of the assets acquired and liabilities assumed at the acquisition date:

Inventories	$	632
Derivative and other current assets	658
Property, plant and equipment	9,152
Intangibles	5,800
Total identifiable assets acquired	16,242
Derivative and other current liabilities	(680		)
Net identifiable assets acquired	15,562
Goodwill	5,081
Net assets acquired	$	20,643

The goodwill recognized is primarily attributable to L.E. Belcher's reputation in the Springfield, Massachusetts area, the in-place workforce and the residual cash flow the Partnership believes that it will be able to generate.

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Accumulated Other Comprehensive Loss, Net of Tax

9 Months Ended

Sep. 30, 2018

Equity [Abstract]

Accumulated Other Comprehensive Loss, Net of Tax

Accumulated Other Comprehensive Loss, Net of Tax

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

	September 30, 2018			December 31, 2017
Fair value of interest rate swaps, net of tax	$	5,899		$	2,588
Cumulative foreign currency translation adjustment	(11,537		)	(11,458		)
Accumulated other comprehensive loss, net of tax	$	(5,638	)	$	(8,870	)

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Inventories

9 Months Ended

Sep. 30, 2018

Inventory Disclosure [Abstract]

Inventories

Inventories

	September 30, 2018		December 31, 2017
Petroleum and related products	$	207,975	$	329,712
Coal	821		3,712
Natural gas	3,150		2,435
Inventories	$	211,946	$	335,859

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Credit Agreement

9 Months Ended

Sep. 30, 2018

Debt Disclosure [Abstract]

Credit Agreement

Credit Agreement

	September 30, 2018			December 31, 2017
Working capital facilities	$	236,400		$	341,850
Acquisition facility	379,100			383,500
Total credit agreement	615,500			725,350
Less: current portion of working capital facilities	(40,545		)	(275,613		)
Long-term portion	$	574,955		$	449,737

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 September 30, 2018, 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 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 September 30, 2018 and December 31, 2017, had a borrowing base of $402.4 million and $623.2 million, respectively. As of September 30, 2018 and December 31, 2017, outstanding letters of credit were $41.3 million and $72.3 million, respectively. As of September 30, 2018, excess availability under the working capital facilities was $124.7 million and excess availability under the acquisition facilities was $170.9 million.

The weighted average interest rate was 5.0% and 4.2% at September 30, 2018 and December 31, 2017, respectively. No amounts are due under the Credit Agreement until the maturity date, however, the current portion of the Credit Agreement at September 30, 2018 and December 31, 2017 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 September 30, 2018, the Partnership was in compliance with these covenants.

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Related Party Transactions

9 Months Ended

Sep. 30, 2018

Related Party Transactions [Abstract]

Related Party Transactions

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 $24.5 million and $19.7 million for the three months ended September 30, 2018 and 2017, and $87.4 million and $67.9 million for the nine months endedSeptember 30, 2018 and 2017, respectively. Through the General Partner, the Partnership also participates in the Parent’s pension and other post-retirement benefits. At September 30, 2018 and December 31, 2017, total amounts due to the General Partner with respect to these benefits and overhead costs were $7.5 million and $12.9 million, respectively.

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Segment Reporting

9 Months Ended

Sep. 30, 2018

Segment Reporting [Abstract]

Segment Reporting

Segment Reporting

The Partnership has four reporting segments that comprise the structure used by the chief operating decision makers (CEO and CFO/COO) 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 reporting segments are refined products, natural gas, materials handling and other activities.

The Partnership's refined products reporting segment purchases a variety of refined products, such as heating oil, diesel fuel, residual fuel oil, asphalt, 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 reporting segment consists of three operating segments.

The Partnership's natural gas reporting 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 reporting segment consists of one operating segment.

The Partnership's materials handling reporting 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 reporting segment consists of two operating segments.

The Partnership's other reporting segment includes the purchase, sale and distribution of coal, commercial trucking activities unrelated to its refined products segment and a heating equipment service business. 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 and nine months ended September 30, 2018 and 2017, respectively. The Partnership’s foreign sales, primarily sales of refined products and natural gas to its customers in Canada, were $69.0 million and $82.5 million for the three months ended September 30, 2018 and 2017, and $205.3 million and $187.0 million for the nine months ended September 30, 2018 and 2017, respectively.

	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
Net sales:
Refined products	$	551,489		$	425,492		$	2,396,374		$	1,638,066
Natural gas	46,908			49,694			235,263			235,068
Materials handling	14,711			11,395			42,077			34,118
Other operations	5,347			4,812			17,545			15,574
Net sales	$	618,455		$	491,393		$	2,691,259		$	1,922,826
Adjusted gross margin (1):
Refined products	$	26,646		$	32,014		$	111,652		$	95,307
Natural gas	3,007			3,197			46,010			44,355
Materials handling	14,683			11,395			42,100			34,118
Other operations	1,715			1,897			5,496			5,800
Adjusted gross margin	46,051			48,503			205,258			179,580
Reconciliation to operating (loss) income (2):
Add/(deduct):
Unrealized (gain) loss on inventory (3)	(3,281		)	(13,673		)	19,309			15,374
Unrealized loss on prepaid forward contracts (4)	—			667			—			907
Unrealized (gain) loss on natural gas transportation contracts (5)	(5,939		)	(760		)	4,413			6,105
Operating costs and expenses not allocated to operating segments:
Operating expenses	(21,047		)	(16,891		)	(66,537		)	(50,624		)
Selling, general and administrative	(16,923		)	(17,559		)	(63,349		)	(63,472		)
Depreciation and amortization	(8,343		)	(6,655		)	(25,146		)	(19,537		)
Operating (loss) income	(9,482		)	(6,368		)	73,948			68,333
Other income	293			—			293			183
Interest income	123			75			404			247
Interest expense	(9,073		)	(7,170		)	(28,369		)	(22,604		)
Income tax provision	(295		)	(853		)	(2,984		)	(3,768		)
Net (loss) income	$	(18,434	)	$	(14,316	)	$	43,292		$	42,391

(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) loss on inventory which is not included in net income (loss), 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) The unrealized loss on prepaid forward contracts represents the Partnership’s estimate of the change in fair value of the prepaid forward contracts which are not recorded in net income until the forward contract is settled in the future (i.e., when the commodity is delivered to the customer). As these contracts are prepaid, they do not qualify as derivatives and changes in the fair value are therefore not included in net income. The fair value of the derivatives the Partnership uses to economically hedge its prepaid forward contracts declines or appreciates in value as the value of the underlying prepaid forward contract appreciates or declines, which creates unrealized hedging gains (losses) that are included in net income.

(5) The unrealized (gain) loss on natural gas transportation contracts 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 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 as of each period end.

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 September 30, 2018, goodwill recorded for the refined products, natural gas, materials handling and other operations segments amounted to $71.4 million, $35.5 million, $6.9 million and $1.2 million, respectively.

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Financial Instruments and Off-Balance Sheet Risk

9 Months Ended

Sep. 30, 2018

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Financial Instruments and Off-Balance Sheet Risk

Financial Instruments and Off-Balance Sheet Risk

As of September 30, 2018 and December 31, 2017, the carrying amounts of cash, cash equivalents and accounts receivable approximated fair value because of the short maturity of these instruments. As of September 30, 2018 and December 31, 2017, 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 September 30, 2018 and December 31, 2017, 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 September 30, 2018, 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 September 30, 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	$	14,209	$	—	$	14,209	$	—
Futures, swaps and options	42,571		42,566		5		—
Commodity derivatives	56,780		42,566		14,214		—
Interest rate swaps	5,993		—		5,993		—
Other	14		—		14		—
Total derivative assets	$	62,787	$	42,566	$	20,221	$	—
Derivative liabilities:
Commodity fixed forwards	$	42,175	$	—	$	42,175	$	—
Futures, swaps and options	37,862		37,858		4		—
Commodity derivatives	80,037		37,858		42,179		—
Interest rate swaps	48		—		48		—
Total derivative liabilities	$	80,085	$	37,858	$	42,227	$	—
Contingent consideration	$	10,246	$	—	$	—	$	10,246

	As of December 31, 2017
	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	$	11,502	$	—	$	11,502	$	—
Futures, swaps and options	100,630		100,613		17		—
Commodity derivatives	112,132		100,613		11,519		—
Interest rate swaps	2,615		—		2,615		—
Total derivative assets	$	114,747	$	100,613	$	14,134	$	—
Derivative liabilities:
Commodity fixed forwards	$	61,195	$	—	$	61,195	$	—
Futures, swaps and options	103,827		103,654		173		—
Commodity derivatives	165,022		103,654		61,368		—
Interest rate swaps	6		—		6		—
Total derivative liabilities	$	165,028	$	103,654	$	61,374	$	—
Contingent consideration	$	9,725	$	—	$	—	$	9,725

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. Substantially all of the Partnership’s commodity derivative contracts outstanding as of September 30, 2018 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:

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 September 30, 2018 and December 31, 2017.

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 $25.4 million at September 30, 2018. Information related to these offsetting arrangements is set forth below:

	As of September 30, 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	$	56,780		$	(37,423	)	$	—	$	19,357
Interest rate swap derivative assets	5,993			—			—		5,993
Other	14			—			—		14
Fair value of derivative assets	$	62,787		$	(37,423	)	$	—	$	25,364
Commodity derivative liabilities	$	(80,037	)	$	37,423		$	10,121	$	(32,493	)
Interest rate swap derivative liabilities	(48		)	—			—		(48		)
Fair value of derivative liabilities	$	(80,085	)	$	37,423		$	10,121	$	(32,541	)

	As of December 31, 2017
				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	$	112,132		$	(86,493	)	$	(4,303	)	$	21,336
Interest rate swap derivative assets	2,615			—			—			2,615
Fair value of derivative assets	$	114,747		$	(86,493	)	$	(4,303	)	$	23,951
Commodity derivative liabilities	$	(165,022	)	$	86,493		$	20,975		$	(57,554	)
Interest rate swap derivative liabilities	(6		)	—			—			(6		)
Fair value of derivative liabilities	$	(165,028	)	$	86,493		$	20,975		$	(57,560	)

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 September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
Refined products contracts	$	1,087		$	(17,281	)	$	10,063		$	27,637
Natural gas contracts	(6,244		)	(908		)	(9,204		)	13,850
Total	$	(5,157	)	$	(18,189	)	$	859		$	41,487

There were no discretionary trading activities for the three and nine months ended September 30, 2018 and 2017. The following table presents gross volume of commodity derivative instruments outstanding for the periods indicated:

	As of September 30, 2018				As of December 31, 2017
	Refined Products (Barrels)		Natural Gas (MMBTUs)		Refined Products (Barrels)		Natural Gas (MMBTUs)
Long contracts	4,552		126,453		9,255		133,532
Short contracts	(6,837	)	(71,121	)	(13,487	)	(72,074	)

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 actual and forecasted LIBOR borrowings and have been designated as cash flow hedges. Counterparties to the Partnership’s interest rate swaps are large multinational banks and the Partnership does not believe there is a material risk of counterparty non-performance.

The Partnership's interest rate swap agreements outstanding as of September 30, 2018 were as follows:

Beginning	Ending	Notional Amount
January 2018	January 2019	$	275,000
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 and nine months ended September 30, 2018 and 2017.

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 September 30, 2018, the amount of unrealized gains, net of tax, expected to be reclassified to earnings during the following twelve-month period was $1.9 million.

Contingent Consideration

As part of the Coen Energy acquisition in 2017, the Partnership may be 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 statements of operations.

The Partnership records changes in the estimated fair value of the contingent consideration within selling, general and administrative expenses in the condensed consolidated statements of operations. Changes in the contingent consideration liability are measured at fair value on a recurring basis using unobservable inputs (Level 3) and during fiscal 2018 are as follows:

Contingent consideration - December 31, 2017	$	9,725
Change in estimated fair value	521
Contingent consideration - September 30, 2018	$	10,246

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Commitments and Contingencies

9 Months Ended

Sep. 30, 2018

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

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. After filing legal action, the Partnership has been assessed $3.5 million of tax, including interest and penalties, for the period of 2013 to 2017, and has provided requested information for previous years. During September 2018, the Partnership received an assessment of $7.3 million, excluding a 15% penalty and interest, from the Ministry of Sustainable Development, Environment, and the Fight Against Climate Change (known as MDDELCC) under separate regulation that was in effect for the period from 2007 through 2014. The Partnership is disputing the MDDELCC 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, 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.

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Equity and Equity-Based Compensation

9 Months Ended

Sep. 30, 2018

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Equity and Equity-Based Compensation

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). Upon vesting, a holder of performance-based phantom units is entitled to receive a number of common units of the Partnership equal to a percentage (between 0 and 200%) of the phantom units granted, based on the Partnership’s achieving pre-determined performance criteria. The Partnership uses authorized but unissued units to satisfy its unit-based obligations.

OCF-based Phantom Units

Phantom unit awards granted in 2018, 2017 and 2016 include a performance criteria that considers Sprague Holdings operating cash flow, as defined ("OCF"), over a three year performance 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 related to the OCF based awards is estimated each reporting period by multiplying the number of common units underlying such awards that, based on the Partnership's estimate of OCF, are probable to vest, by the grant-date fair value of the award and is recognized over the requisite service period using the straight-line method. The fair value of the OCF based phantom units is the grant date closing price listed on the New York Stock Exchange. 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.

Distribution Equivalent Rights

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.

A summary of the Partnership’s unit awards subject to vesting during the nine months ended September 30,2018 is set forth below:

	2018 Awards					2017 Awards					2016 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, 2017	—		$	—		131,000		$	26.96		163,900		$	17.52
Granted	143,981		23.30			—		—			—		—
Forfeited	(5,460	)	(23.30		)	(3,208	)	(26.95		)	(1,202	)	(17.52		)
Vested	—		—			—		—			—		—
Nonvested at September 30, 2018	138,521		$	23.30		127,792		$	26.96		162,698		$	17.52

During the nine-months ended September 30, 2018, the Partnership reduced its estimates of the number of units expected to vest over the vesting periods and as a result unit-based compensation for the three and nine months ended September 30,2018 was $(0.3) million and $(0.1) million, respectively, as compared to $(0.2) million and $1.7 million, for the three and nine months ended September 30,2017. Unit-based compensation is included in selling, general and administrative expenses. Unrecognized compensation cost related to performance-based phantom unit awards totaled $3.5 million as of September 30, 2018 which is expected to be recognized over a weighted average period of 14 months.

Equity - Changes in Partnership Units

Phantom units with a performance period ended as of December 31, 2017 vested at the 195.5% level and as a result 271,748 common units (vested market value of $7.0 million) were issued during January 2018, with 97,351 units being withheld to satisfy tax withholding requirements.

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

	Common Units
	Public	Sprague Holdings	Subordinated Units
Balance as of December 31, 2016	9,207,473	2,034,378	10,071,970
Conversion of subordinated units	—	10,071,970	(10,071,970	)
Units issued in connection with performance awards	89,315	—	—
Units issued in connection with employee bonus	8,840	—	—
Director vested awards	9,360	—	—
Units issued in connection with Carbo acquisition	1,131,551	—	—
Balance as of December 31, 2017	10,446,539	12,106,348	—
Units issued in connection with performance awards	174,397	—	—
Balance as of September 30, 2018	10,620,936	12,106,348	—

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Earnings Per Unit

9 Months Ended

Sep. 30, 2018

Earnings Per Share [Abstract]

Earnings Per Unit

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 (loss), after deducting any incentive distributions, by the weighted-average number of outstanding common and subordinated 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 (loss) allocations used in the calculation of earnings (loss) per unit. Quarterly net income (loss) per limited partner and per unit amounts are stand-alone calculations and may not be additive to year to date amounts due to rounding and changes in outstanding units.

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

	Three Months Ended September 30,		Nine Months Ended September 30,
	2018	2017	2018	2017
Weighted average limited partner common units - basic	22,727,284	22,543,527	22,726,645	22,093,578
Dilutive effect of unvested phantom units	—	—	40,080	274,854
Weighted average limited partner common units - dilutive	22,727,284	22,543,527	22,766,725	22,368,432

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Partnership Distributions

9 Months Ended

Sep. 30, 2018

Equity [Abstract]

Partnership Distributions

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:

Three Months Ended	Payment Date	Per Unit	Common		IDR		DER		Total
December 31, 2017	February 12, 2018	$0.6375	$	14,489	$	1,373	$	1,760	$	17,622
March 31, 2018	May 18, 2018	$0.6525	$	14,830	$	1,714	$	—	$	16,544
June 30, 2018	August 10, 2018	$0.6675	$	15,170	$	2,055	$	—	$	17,225

In addition, on October 26, 2018, the Partnership declared a cash distribution for the three months ended September 30, 2018, of $0.6675 per unit, totaling $17.2 million (including a $2.1 million IDR distribution). Such distributions are to be paid on November 13, 2018, to unitholders of record on November 6, 2018.

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Description of Business and Summary of Significant Accounting Policies (Policies)

9 Months Ended

Sep. 30, 2018

Accounting Policies [Abstract]

Basis of Presentation

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, 2017 as filed with the SEC on March 14, 2018 (the “2017 Annual Report”).

The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities in the balance sheet and the reported net sales and expenses in the income statement. Actual results could differ from those estimates. Among the estimates made by management are asset and liability valuations as part of an acquisition, 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 September 30, 2018 and December 31, 2017, the consolidated results of operations for the three and nine months ended September 30, 2018 and 2017, and the consolidated cash flows for the nine months ended September 30, 2018 and 2017. 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.

Recent Accounting Pronouncements

Recent Accounting Pronouncements

In July 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2017-12, Derivatives and Hedging: 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 Partnership is currently evaluating the impact of this new standard on the 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 January 2017, the FASB issued ASU 2017-01 Business Combinations (Topic 805), whichclarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. This ASU is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. The Partnership will follow this new guidance for transactions entered into after December 31, 2017.

In August 2016, the FASB issued ASU 2016-15 Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments, which addresses eight specific cash flow issues with the objective of reducing diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows under Topic 230, Statement of Cash Flows, and other Topics. This ASU is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years and is to be applied retrospectively to all periods presented. The adoption of this guidance in 2018 did not have an impact on the Partnership's consolidated statements of cash flows.

In February 2016, the FASB issued ASU 2016-02 Leases (Topic 842), which, among other things, requires lessees to recognize at the commencement date of a lease a liability, which is a lessee's 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. This ASU is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. In June 2018, the FASB issued ASU 2018-11 that introduced a transition option, that the Partnership intends to adopt, that will allow the new standard to be adopted without revising comparative period reporting or disclosures. The Partnership has started the process of gathering and analyzing its lease contracts and is in the process of evaluating changes to business processes, systems and controls needed to support recognition and disclosure under this new standard. While the adoption of this new standard is expected to result in an increase to reported assets and liabilities, the Partnership has not yet determined the full impact that the adoption of ASU 2016-02 will have on its consolidated financial statements.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606), which revises the

principles of revenue recognition from one based on the transfer of risks and rewards to when a customer obtains control of a

good or service. The FASB issued several ASUs after ASU 2014-09 to clarify implementation guidance but did not change the core principle of the guidance in Topic 606. These ASUs are effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. The adoption of this standard in 2018 did not have an impact on the Partnership's consolidated financial statements nor result in significant changes to business processes, systems, or internal controls.

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Revenue (Tables)

9 Months Ended

Sep. 30, 2018

Revenue from Contract with Customer [Abstract]

Disaggregation of Revenue

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
Net sales:
Refined products
Distillates	$	403,186	$	279,381	$	1,890,740	$	1,217,866
Gasoline	88,536		71,971		252,852		208,669
Heavy fuel oil and asphalt	59,767		74,140		252,782		211,531
Total refined products	$	551,489	$	425,492	$	2,396,374	$	1,638,066
Natural gas	46,908		49,694		235,263		235,068
Materials handling	14,711		11,395		42,077		34,118
Other operations	5,347		4,812		17,545		15,574
Net sales	$	618,455	$	491,393	$	2,691,259	$	1,922,826
Net sales by Country:
United States	$	549,477	$	408,897	$	2,485,922	$	1,735,778
Canada	$	68,978	$	82,496	$	205,337	187,048
Net sales	$	618,455	$	491,393	$	2,691,259	$	1,922,826

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Business Combinations (Tables)

9 Months Ended

Sep. 30, 2018

Business Combinations [Abstract]

Schedule of Recognized Identified Assets Acquired and Liabilities Assumed

tion date.

    The following table summarizes the fair values of the assets acquired and liabilities assumed at the acquisit

and truck. The operations of Carbo are included in the Partnership's refined products segment since the acquisition date.

The following table summarizes the fair values of the assets acquired and liabilities assumed at the acquisit

te.

The following table summarizes the fair values of the assets acquired and liabilities assumed at the acquisit

ition date.

The following table summarizes the fair values of the assets acquired and liabilities assumed at the acquisi

date.

The following table summarizes the fair values of the assets acquired and liabilities assumed at the acquisit

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Accumulated Other Comprehensive Loss, Net of Tax (Tables)

9 Months Ended

Sep. 30, 2018

Equity [Abstract]

Schedule of Accumulated Other Comprehensive Loss, Net of Tax

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

	September 30, 2018			December 31, 2017
Fair value of interest rate swaps, net of tax	$	5,899		$	2,588
Cumulative foreign currency translation adjustment	(11,537		)	(11,458		)
Accumulated other comprehensive loss, net of tax	$	(5,638	)	$	(8,870	)

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Inventories (Tables)

9 Months Ended

Sep. 30, 2018

Inventory Disclosure [Abstract]

Schedule of Inventories

	September 30, 2018		December 31, 2017
Petroleum and related products	$	207,975	$	329,712
Coal	821		3,712
Natural gas	3,150		2,435
Inventories	$	211,946	$	335,859

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Credit Agreement (Tables)

9 Months Ended

Sep. 30, 2018

Debt Disclosure [Abstract]

Schedule of Debt

	September 30, 2018			December 31, 2017
Working capital facilities	$	236,400		$	341,850
Acquisition facility	379,100			383,500
Total credit agreement	615,500			725,350
Less: current portion of working capital facilities	(40,545		)	(275,613		)
Long-term portion	$	574,955		$	449,737

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Segment Reporting (Tables)

9 Months Ended

Sep. 30, 2018

Segment Reporting [Abstract]

Summary of Financial Information for Partnership's Reportable Segments

	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
Net sales:
Refined products	$	551,489		$	425,492		$	2,396,374		$	1,638,066
Natural gas	46,908			49,694			235,263			235,068
Materials handling	14,711			11,395			42,077			34,118
Other operations	5,347			4,812			17,545			15,574
Net sales	$	618,455		$	491,393		$	2,691,259		$	1,922,826
Adjusted gross margin (1):
Refined products	$	26,646		$	32,014		$	111,652		$	95,307
Natural gas	3,007			3,197			46,010			44,355
Materials handling	14,683			11,395			42,100			34,118
Other operations	1,715			1,897			5,496			5,800
Adjusted gross margin	46,051			48,503			205,258			179,580
Reconciliation to operating (loss) income (2):
Add/(deduct):
Unrealized (gain) loss on inventory (3)	(3,281		)	(13,673		)	19,309			15,374
Unrealized loss on prepaid forward contracts (4)	—			667			—			907
Unrealized (gain) loss on natural gas transportation contracts (5)	(5,939		)	(760		)	4,413			6,105
Operating costs and expenses not allocated to operating segments:
Operating expenses	(21,047		)	(16,891		)	(66,537		)	(50,624		)
Selling, general and administrative	(16,923		)	(17,559		)	(63,349		)	(63,472		)
Depreciation and amortization	(8,343		)	(6,655		)	(25,146		)	(19,537		)
Operating (loss) income	(9,482		)	(6,368		)	73,948			68,333
Other income	293			—			293			183
Interest income	123			75			404			247
Interest expense	(9,073		)	(7,170		)	(28,369		)	(22,604		)
Income tax provision	(295		)	(853		)	(2,984		)	(3,768		)
Net (loss) income	$	(18,434	)	$	(14,316	)	$	43,292		$	42,391

(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) loss on inventory which is not included in net income (loss), 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) The unrealized loss on prepaid forward contracts represents the Partnership’s estimate of the change in fair value of the prepaid forward contracts which are not recorded in net income until the forward contract is settled in the future (i.e., when the commodity is delivered to the customer). As these contracts are prepaid, they do not qualify as derivatives and changes in the fair value are therefore not included in net income. The fair value of the derivatives the Partnership uses to economically hedge its prepaid forward contracts declines or appreciates in value as the value of the underlying prepaid forward contract appreciates or declines, which creates unrealized hedging gains (losses) that are included in net income.

(5) The unrealized (gain) loss on natural gas transportation contracts 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 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 as of each period end.

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Financial Instruments and Off-Balance Sheet Risk (Tables)

9 Months Ended

Sep. 30, 2018

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Summary of Financial Assets and Financial Liabilities of Partnership Measured at Fair Value on Recurring Basis

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

	As of September 30, 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	$	14,209	$	—	$	14,209	$	—
Futures, swaps and options	42,571		42,566		5		—
Commodity derivatives	56,780		42,566		14,214		—
Interest rate swaps	5,993		—		5,993		—
Other	14		—		14		—
Total derivative assets	$	62,787	$	42,566	$	20,221	$	—
Derivative liabilities:
Commodity fixed forwards	$	42,175	$	—	$	42,175	$	—
Futures, swaps and options	37,862		37,858		4		—
Commodity derivatives	80,037		37,858		42,179		—
Interest rate swaps	48		—		48		—
Total derivative liabilities	$	80,085	$	37,858	$	42,227	$	—
Contingent consideration	$	10,246	$	—	$	—	$	10,246

	As of December 31, 2017
	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	$	11,502	$	—	$	11,502	$	—
Futures, swaps and options	100,630		100,613		17		—
Commodity derivatives	112,132		100,613		11,519		—
Interest rate swaps	2,615		—		2,615		—
Total derivative assets	$	114,747	$	100,613	$	14,134	$	—
Derivative liabilities:
Commodity fixed forwards	$	61,195	$	—	$	61,195	$	—
Futures, swaps and options	103,827		103,654		173		—
Commodity derivatives	165,022		103,654		61,368		—
Interest rate swaps	6		—		6		—
Total derivative liabilities	$	165,028	$	103,654	$	61,374	$	—
Contingent consideration	$	9,725	$	—	$	—	$	9,725

Summary of Offsetting Assets

Information related to these offsetting arrangements is set forth below:

	As of September 30, 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	$	56,780		$	(37,423	)	$	—	$	19,357
Interest rate swap derivative assets	5,993			—			—		5,993
Other	14			—			—		14
Fair value of derivative assets	$	62,787		$	(37,423	)	$	—	$	25,364
Commodity derivative liabilities	$	(80,037	)	$	37,423		$	10,121	$	(32,493	)
Interest rate swap derivative liabilities	(48		)	—			—		(48		)
Fair value of derivative liabilities	$	(80,085	)	$	37,423		$	10,121	$	(32,541	)

	As of December 31, 2017
				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	$	112,132		$	(86,493	)	$	(4,303	)	$	21,336
Interest rate swap derivative assets	2,615			—			—			2,615
Fair value of derivative assets	$	114,747		$	(86,493	)	$	(4,303	)	$	23,951
Commodity derivative liabilities	$	(165,022	)	$	86,493		$	20,975		$	(57,554	)
Interest rate swap derivative liabilities	(6		)	—			—			(6		)
Fair value of derivative liabilities	$	(165,028	)	$	86,493		$	20,975		$	(57,560	)

Summary of Offsetting Liabilities

Information related to these offsetting arrangements is set forth below:

	As of September 30, 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	$	56,780		$	(37,423	)	$	—	$	19,357
Interest rate swap derivative assets	5,993			—			—		5,993
Other	14			—			—		14
Fair value of derivative assets	$	62,787		$	(37,423	)	$	—	$	25,364
Commodity derivative liabilities	$	(80,037	)	$	37,423		$	10,121	$	(32,493	)
Interest rate swap derivative liabilities	(48		)	—			—		(48		)
Fair value of derivative liabilities	$	(80,085	)	$	37,423		$	10,121	$	(32,541	)

	As of December 31, 2017
				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	$	112,132		$	(86,493	)	$	(4,303	)	$	21,336
Interest rate swap derivative assets	2,615			—			—			2,615
Fair value of derivative assets	$	114,747		$	(86,493	)	$	(4,303	)	$	23,951
Commodity derivative liabilities	$	(165,022	)	$	86,493		$	20,975		$	(57,554	)
Interest rate swap derivative liabilities	(6		)	—			—			(6		)
Fair value of derivative liabilities	$	(165,028	)	$	86,493		$	20,975		$	(57,560	)

Summary of Realized and Unrealized Gains (Losses) on Derivative Instruments for Commodity Risk Management

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 September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
Refined products contracts	$	1,087		$	(17,281	)	$	10,063		$	27,637
Natural gas contracts	(6,244		)	(908		)	(9,204		)	13,850
Total	$	(5,157	)	$	(18,189	)	$	859		$	41,487

Schedule of Gross Volume of Commodity Derivative Instruments Outstanding

The following table presents gross volume of commodity derivative instruments outstanding for the periods indicated:

	As of September 30, 2018				As of December 31, 2017
	Refined Products (Barrels)		Natural Gas (MMBTUs)		Refined Products (Barrels)		Natural Gas (MMBTUs)
Long contracts	4,552		126,453		9,255		133,532
Short contracts	(6,837	)	(71,121	)	(13,487	)	(72,074	)

Schedule of Notional Amounts

The Partnership's interest rate swap agreements outstanding as of September 30, 2018 were as follows:

Beginning	Ending	Notional Amount
January 2018	January 2019	$	275,000
January 2019	January 2020	$	300,000
January 2020	January 2021	$	300,000
January 2021	January 2022	$	300,000
January 2022	January 2023	$	250,000

Summary of Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation

Changes in the contingent consideration liability are measured at fair value on a recurring basis using unobservable inputs (Level 3) and during fiscal 2018 are as follows:

Contingent consideration - December 31, 2017	$	9,725
Change in estimated fair value	521
Contingent consideration - September 30, 2018	$	10,246

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Equity and Equity-Based Compensation (Tables)

9 Months Ended

Sep. 30, 2018

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Summary of Partnership's Unit Awards Subject to Vesting

A summary of the Partnership’s unit awards subject to vesting during the nine months ended September 30,2018 is set forth below:

	2018 Awards					2017 Awards					2016 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, 2017	—		$	—		131,000		$	26.96		163,900		$	17.52
Granted	143,981		23.30			—		—			—		—
Forfeited	(5,460	)	(23.30		)	(3,208	)	(26.95		)	(1,202	)	(17.52		)
Vested	—		—			—		—			—		—
Nonvested at September 30, 2018	138,521		$	23.30		127,792		$	26.96		162,698		$	17.52

Schedule of Changes in Partnership's Units

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

	Common Units
	Public	Sprague Holdings	Subordinated Units
Balance as of December 31, 2016	9,207,473	2,034,378	10,071,970
Conversion of subordinated units	—	10,071,970	(10,071,970	)
Units issued in connection with performance awards	89,315	—	—
Units issued in connection with employee bonus	8,840	—	—
Director vested awards	9,360	—	—
Units issued in connection with Carbo acquisition	1,131,551	—	—
Balance as of December 31, 2017	10,446,539	12,106,348	—
Units issued in connection with performance awards	174,397	—	—
Balance as of September 30, 2018	10,620,936	12,106,348	—

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Earnings Per Unit (Tables)

9 Months Ended

Sep. 30, 2018

Earnings Per Share [Abstract]

Summary of Weighted Average Common Units Outstanding

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

	Three Months Ended September 30,		Nine Months Ended September 30,
	2018	2017	2018	2017
Weighted average limited partner common units - basic	22,727,284	22,543,527	22,726,645	22,093,578
Dilutive effect of unvested phantom units	—	—	40,080	274,854
Weighted average limited partner common units - dilutive	22,727,284	22,543,527	22,766,725	22,368,432

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Partnership Distributions (Tables)

9 Months Ended

Sep. 30, 2018

Equity [Abstract]

Schedule of Incentive Distribution Amounts

Cash distributions for the periods indicated were as follows:

Three Months Ended	Payment Date	Per Unit	Common		IDR		DER		Total
December 31, 2017	February 12, 2018	$0.6375	$	14,489	$	1,373	$	1,760	$	17,622
March 31, 2018	May 18, 2018	$0.6525	$	14,830	$	1,714	$	—	$	16,544
June 30, 2018	August 10, 2018	$0.6675	$	15,170	$	2,055	$	—	$	17,225

XML

Description of Business and Summary of Significant Accounting Policies - Additional Information (Details)	9 Months Ended	12 Months Ended
	Sep. 30, 2018 segment $ / shares shares	Dec. 31, 2016 $ / shares	Feb. 16, 2017 shares
Nature Of Business And Basis Of Presentation [Line Items]
Number of reporting operating segments | segment	4
Subordinated units, conversion ratio	1
Sprague Resources Holdings Llc
Nature Of Business And Basis Of Presentation [Line Items]
Distributions from distributable cash flow (in dollars per share) | $ / shares	$ 0.474375
Sprague Resources Holdings Llc | Maximum
Nature Of Business And Basis Of Presentation [Line Items]
Percentages incentive distribution rights	50.00%
Sprague Resources LP | Common Stock | Axel Johnson Inc.
Nature Of Business And Basis Of Presentation [Line Items]
Common units issued (in shares) | shares	12,106,348
Limited partnership, ownership interest	53.00%
Common Units
Nature Of Business And Basis Of Presentation [Line Items]
Distributions from distributable cash flow (in dollars per share) | $ / shares		$ 0.4125
Affiliated Entity | Subordinated Units
Nature Of Business And Basis Of Presentation [Line Items]
Common units issued (in shares) | shares			10,071,970

XML

Revenue (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Disaggregation of Revenue [Line Items]
Payment terms			30 days
Revenue, performance obligation, description of timing			one year or less
Contract liabilities	$ 7,800		$ 7,800		$ 7,700
Net sales	618,455	$ 491,393	2,691,259	$ 1,922,826
United States
Disaggregation of Revenue [Line Items]
Net sales	549,477	408,897	2,485,922	1,735,778
Canada
Disaggregation of Revenue [Line Items]
Net sales	68,978	82,496	205,337	187,048
Distillates
Disaggregation of Revenue [Line Items]
Net sales	403,186	279,381	1,890,740	1,217,866
Gasoline
Disaggregation of Revenue [Line Items]
Net sales	88,536	71,971	252,852	208,669
Heavy fuel oil and asphalt
Disaggregation of Revenue [Line Items]
Net sales	59,767	74,140	252,782	211,531
Refined products
Disaggregation of Revenue [Line Items]
Net sales	551,489	425,492	2,396,374	1,638,066
Natural gas
Disaggregation of Revenue [Line Items]
Net sales	46,908	49,694	235,263	235,068
Materials handling
Disaggregation of Revenue [Line Items]
Net sales	14,711	11,395	42,077	34,118
Other operations
Disaggregation of Revenue [Line Items]
Net sales	$ 5,347	$ 4,812	$ 17,545	$ 15,574

XML

Business Combinations - Additional Information (Detail) bbl in Thousands, $ in Millions					3 Months Ended		9 Months Ended		12 Months Ended
	Oct. 01, 2017 USD ($) asset	Apr. 18, 2017 USD ($) bbl	Feb. 10, 2017 USD ($) bbl	Feb. 01, 2017 USD ($) pipeline_supplied_distillate_terminal bbl distillate_storage_facility	Sep. 30, 2018 USD ($)	Sep. 30, 2017 USD ($)	Sep. 30, 2018 USD ($)	Sep. 30, 2017 USD ($)	Dec. 31, 2017 employee asset business_acquisition
Business Acquisition [Line Items]
Number of businesses acquired | business_acquisition									5
Business acquisition, pro forma revenue							$ 514.0	$ 2,025.0
Coen Energy, LLC And Coen Transport, LLC
Business Acquisition [Line Items]
Business combination, contingent consideration, liability	$ 12.0
Total consideration	$ 35.3
Entity number of employees | employee									250
Carbo Industries
Business Acquisition [Line Items]
Payments to acquire businesses		$ 13.3
Total consideration		72.0
Liability incurred to acquire business		$ 38.2
Pay-off period of liability incurred to acquire business		10 years
Net present value of liability incurred to acquire business		$ 27.3
Common units issued, value, to acquire business		$ 31.4
Capacity of terminal facility acquired (barrels) | bbl		174
Capital Terminal
Business Acquisition [Line Items]
Payments to acquire businesses			$ 22.0
Distillate terminal capacity, barrels | bbl			1,000
Global Natural Gas & Power
Business Acquisition [Line Items]
Payments to acquire businesses				$ 16.3
Total consideration				17.3
Leonard E Belcher, Inc.
Business Acquisition [Line Items]
Payments to acquire businesses				20.7
Total consideration				$ 20.0
Pipeline-supplied distillate terminals acquired | pipeline_supplied_distillate_terminal				2
Distillate storage facilities acquired | distillate_storage_facility				1
Distillate terminals and storage facility combine capacity, barrels | bbl				283
In-land bulk plan | Coen Energy, LLC And Coen Transport, LLC
Business Acquisition [Line Items]
Property, plant and equipment, number of assets | asset	4
Throughput locations | Coen Energy, LLC And Coen Transport, LLC
Business Acquisition [Line Items]
Property, plant and equipment, number of assets | asset	2
Transportation equipment | Coen Energy, LLC And Coen Transport, LLC
Business Acquisition [Line Items]
Property, plant and equipment, number of assets | asset									100
Selling, general and administrative expenses
Business Acquisition [Line Items]
Business combination, acquisition related costs					$ 0.1	$ 0.7	$ 0.7	$ 1.7

XML

Business Combinations - Fair Value of Assets Acquired and Liabilities Assumed (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017	Oct. 01, 2017	Apr. 18, 2017	Feb. 10, 2017	Feb. 01, 2017
Business Acquisition [Line Items]
Goodwill	$ 115,037	$ 115,037
Coen Energy, LLC And Coen Transport, LLC
Business Acquisition [Line Items]
Inventories			$ 567
Other current assets			115
Property, plant and equipment			12,972
Intangibles			18,375
Total identifiable assets acquired			32,029
Other liabilities			(256)
Net identifiable assets acquired			31,773
Goodwill			13,095
Net assets acquired			$ 44,868
Carbo Industries
Business Acquisition [Line Items]
Inventories				$ 3,220
Derivative and other current assets				111
Property, plant and equipment				22,995
Intangibles				29,000
Total identifiable assets acquired				55,326
Other liabilities				(188)
Net identifiable assets acquired				55,138
Goodwill				16,718
Net assets acquired				$ 71,856
Capital Terminal
Business Acquisition [Line Items]
Property, plant and equipment					$ 21,960
Accrued liabilities and other, net					(22)
Net assets acquired					$ 21,938
Global Natural Gas & Power
Business Acquisition [Line Items]
Inventories						$ 286
Derivative and other current assets						5,873
Natural gas transportation assets						695
Derivative assets long term						1,089
Natural gas transportation assets long term						378
Intangibles						5,046
Total identifiable assets acquired						13,367
Derivative liabilities						(4,865)
Natural gas transportation liabilities						(465)
Derivative liabilities long term						(1,214)
Natural gas transportation liabilities long term						(162)
Net identifiable assets acquired						6,661
Goodwill						9,592
Net assets acquired						16,253
Leonard E Belcher, Inc.
Business Acquisition [Line Items]
Inventories						632
Derivative and other current assets						658
Property, plant and equipment						9,152
Intangibles						5,800
Total identifiable assets acquired						16,242
Derivative liabilities						(680)
Net identifiable assets acquired						15,562
Goodwill						5,081
Net assets acquired						$ 20,643

XML

Accumulated Other Comprehensive Loss, Net of Tax - Schedule of Accumulated Other Comprehensive Loss, Net of Tax (Detail) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017	Dec. 31, 2016
Accumulated Other Comprehensive Income (Loss) [Line Items]
Partners' Capital	$ 124,368	$ 131,834	$ 125,437
Fair value of interest rate swaps, net of tax
Accumulated Other Comprehensive Income (Loss) [Line Items]
Partners' Capital	5,899	2,588
Cumulative foreign currency translation adjustment
Accumulated Other Comprehensive Income (Loss) [Line Items]
Partners' Capital	(11,537)	(11,458)
Accumulated other comprehensive loss, net of tax
Accumulated Other Comprehensive Income (Loss) [Line Items]
Partners' Capital	$ (5,638)	$ (8,870)	$ (10,783)

XML

Inventories - Schedule of Inventories (Detail) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Inventory [Line Items]
Inventories	$ 211,946	$ 335,859
Petroleum and related products
Inventory [Line Items]
Inventories	207,975	329,712
Coal
Inventory [Line Items]
Inventories	821	3,712
Natural gas
Inventory [Line Items]
Inventories	$ 3,150	$ 2,435

XML

Credit Agreement - Schedule of Debt (Detail) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Line of Credit Facility [Line Items]
Credit agreement	$ 615,500	$ 725,350
Less: current portion of working capital facilities	(40,545)	(275,613)
Long-term portion	574,955	449,737
Working capital facilities
Line of Credit Facility [Line Items]
Credit agreement	236,400	341,850
Long-term portion	195,855	66,237
Acquisition facility
Line of Credit Facility [Line Items]
Credit agreement	379,100	383,500
Long-term portion	$ 379,100	$ 383,500

XML

Credit Agreement - Additional Information (Detail) - USD ($)	9 Months Ended
	Sep. 30, 2018	Dec. 31, 2017
Working capital facilities | Federal Funds Rate | U.S. dollar
Debt Instrument [Line Items]
Debt instruments, interest rate	0.50%
Working capital facilities | Eurocurrency Rate | U.S. dollar
Debt Instrument [Line Items]
Debt instruments, interest rate	1.00%
Working capital facilities | Eurocurrency Rate | Canadian dollars
Debt Instrument [Line Items]
Debt instruments, interest rate	1.00%
Working capital facilities | Amended and Restated Revolving Credit Agreement
Debt Instrument [Line Items]
Debt instrument, potential increase in maximum borrowing capacity	$ 250,000,000.0
Acquisition facility | Amended and Restated Revolving Credit Agreement
Debt Instrument [Line Items]
Debt instrument, potential increase in maximum borrowing capacity	200,000,000.0
Multicurrency working capital | Amended and Restated Revolving Credit Agreement
Debt Instrument [Line Items]
Debt instrument, potential increase in maximum borrowing capacity	220,000,000.0
Working capital and multicurrency facility | Amended and Restated Revolving Credit Agreement
Debt Instrument [Line Items]
Debt instrument, potential increase in maximum borrowing capacity	$ 270,000,000.0
Credit Agreement
Debt Instrument [Line Items]
Debt instruments, weighted average interest rate	5.00%	4.20%
Credit Agreement | One Month London Interbank Offered Rate (LIBOR)
Debt Instrument [Line Items]
Debt instrument, variable rate, term	1 month
Credit Agreement | Two Month London Interbank Offered Rate (LIBOR)
Debt Instrument [Line Items]
Debt instrument, variable rate, term	2 months
Credit Agreement | Three Month London Interbank Offered Rate (LIBOR)
Debt Instrument [Line Items]
Debt instrument, variable rate, term	3 months
Credit Agreement | Six Month London Interbank Offered Rate (LIBOR)
Debt Instrument [Line Items]
Debt instrument, variable rate, term	6 months
Credit Agreement | Working capital facilities
Debt Instrument [Line Items]
Borrowing base under Credit Agreement	$ 402,400,000	$ 623,200,000
Letters of credit outstanding	41,300,000	$ 72,300,000
Excess availability under Credit Agreement	124,700,000
Credit Agreement | Working capital facilities | Amended and Restated Revolving Credit Agreement
Debt Instrument [Line Items]
Debt instruments, borrowing capacity	950,000,000
Credit Agreement | Working capital facilities | Amended and Restated Revolving Credit Agreement | Kildair
Debt Instrument [Line Items]
Debt instruments, borrowing capacity	100,000,000
Credit Agreement | Acquisition facility
Debt Instrument [Line Items]
Excess availability under Credit Agreement	170,900,000
Credit Agreement | Acquisition facility | Amended and Restated Revolving Credit Agreement
Debt Instrument [Line Items]
Debt instruments, borrowing capacity	$ 550,000,000

XML

Related Party Transactions - Additional Information (Detail) - General Partner - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Related Party Transaction [Line Items]
Reimbursements of employee costs and related benefits	$ 24.5	$ 19.7	$ 87.4	$ 67.9
Amounts due to General Partner	$ 7.5		$ 7.5		$ 12.9

XML

Segment Reporting - Additional Information (Detail) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018 USD ($)	Sep. 30, 2017 USD ($)	Sep. 30, 2018 USD ($) segment operating_unit	Sep. 30, 2017 USD ($)	Dec. 31, 2017 USD ($)
Segment Reporting Information [Line Items]
Number of reporting operating segments | segment			4
Revenue from contract with customer, excluding assessed tax	$ 618,455	$ 491,393	$ 2,691,259	$ 1,922,826
Significant fixed assets attributable to reporting segment	350,145		350,145		$ 350,059
Goodwill	115,037		$ 115,037		$ 115,037
Refined products
Segment Reporting Information [Line Items]
Number of operating units | operating_unit			3
Goodwill	71,400		$ 71,400
Natural gas
Segment Reporting Information [Line Items]
Number of operating units | operating_unit			1
Significant fixed assets attributable to reporting segment	0		$ 0
Goodwill	35,500		$ 35,500
Materials handling
Segment Reporting Information [Line Items]
Number of operating units | operating_unit			2
Goodwill	6,900		$ 6,900
Other operations
Segment Reporting Information [Line Items]
Number of operating units | operating_unit			2
Goodwill	1,200		$ 1,200
Canada
Segment Reporting Information [Line Items]
Revenue from contract with customer, excluding assessed tax	$ 68,978	$ 82,496	$ 205,337	$ 187,048

XML

Segment Reporting - Summary of Financial Information for Partnership's Reportable Segments (Detail) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Net sales [Abstract]
Revenue from contract with customer, excluding assessed tax	$ 618,455	$ 491,393	$ 2,691,259	$ 1,922,826
Adjusted gross margin:
Adjusted gross margin	46,051	48,503	205,258	179,580
Reconciliation to operating income (loss):
Unrealized gain (loss) on inventory	(3,281)	(13,673)	19,309	15,374
Unrealized gain on prepaid forward contract derivatives	0	667	0	907
Unrealized (loss) gain on natural gas transportation contracts	(5,939)	(760)	4,413	6,105
Operating costs and expenses not allocated to operating segments:
Operating expenses	(21,047)	(16,891)	(66,537)	(50,624)
Selling, general and administrative	(16,923)	(17,559)	(63,349)	(63,472)
Depreciation and amortization	(8,343)	(6,655)	(25,146)	(19,537)
Operating (loss) income	(9,482)	(6,368)	73,948	68,333
Other income	293	0	293	183
Interest income	123	75	404	247
Interest expense	(9,073)	(7,170)	(28,369)	(22,604)
Income tax provision	(295)	(853)	(2,984)	(3,768)
Net (loss) income	(18,434)	(14,316)	43,292	42,391	$ 29,497
Refined products
Net sales [Abstract]
Revenue from contract with customer, excluding assessed tax	551,489	425,492	2,396,374	1,638,066
Adjusted gross margin:
Adjusted gross margin	26,646	32,014	111,652	95,307
Natural gas
Net sales [Abstract]
Revenue from contract with customer, excluding assessed tax	46,908	49,694	235,263	235,068
Adjusted gross margin:
Adjusted gross margin	3,007	3,197	46,010	44,355
Materials handling
Net sales [Abstract]
Revenue from contract with customer, excluding assessed tax	14,711	11,395	42,077	34,118
Adjusted gross margin:
Adjusted gross margin	14,683	11,395	42,100	34,118
Other operations
Net sales [Abstract]
Revenue from contract with customer, excluding assessed tax	5,347	4,812	17,545	15,574
Adjusted gross margin:
Adjusted gross margin	$ 1,715	$ 1,897	$ 5,496	$ 5,800

XML

Financial Instruments and Off-Balance Sheet Risk - Summary of Financial Assets and Financial Liabilities of Partnership Measured at Fair Value on Recurring Basis (Detail) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Quoted Prices in Active Markets Level 1
Derivative assets:
Financial assets	$ 42,566	$ 100,613
Derivative liabilities:
Financial liabilities	37,858	103,654
Contingent consideration	0	0
Quoted Prices in Active Markets Level 1 | Commodity fixed forwards
Derivative assets:
Financial assets	0	0
Derivative liabilities:
Financial liabilities	0	0
Quoted Prices in Active Markets Level 1 | Futures swaps and options
Derivative assets:
Financial assets	42,566	100,613
Derivative liabilities:
Financial liabilities	37,858	103,654
Quoted Prices in Active Markets Level 1 | Commodity derivatives
Derivative assets:
Financial assets	42,566	100,613
Derivative liabilities:
Financial liabilities	37,858	103,654
Quoted Prices in Active Markets Level 1 | Interest rate swaps
Derivative assets:
Financial assets	0	0
Derivative liabilities:
Financial liabilities	0	0
Quoted Prices in Active Markets Level 1 | Other Assets
Derivative assets:
Financial assets	0
Significant Other Observable Inputs Level 2
Derivative assets:
Financial assets	20,221	14,134
Derivative liabilities:
Financial liabilities	42,227	61,374
Contingent consideration	0	0
Significant Other Observable Inputs Level 2 | Commodity fixed forwards
Derivative assets:
Financial assets	14,209	11,502
Derivative liabilities:
Financial liabilities	42,175	61,195
Significant Other Observable Inputs Level 2 | Futures swaps and options
Derivative assets:
Financial assets	5	17
Derivative liabilities:
Financial liabilities	4	173
Significant Other Observable Inputs Level 2 | Commodity derivatives
Derivative assets:
Financial assets	14,214	11,519
Derivative liabilities:
Financial liabilities	42,179	61,368
Significant Other Observable Inputs Level 2 | Interest rate swaps
Derivative assets:
Financial assets	5,993	2,615
Derivative liabilities:
Financial liabilities	48	6
Significant Other Observable Inputs Level 2 | Other Assets
Derivative assets:
Financial assets	14
Significant Unobservable Inputs Level 3
Derivative assets:
Financial assets	0	0
Derivative liabilities:
Financial liabilities	0	0
Contingent consideration	10,246	9,725
Significant Unobservable Inputs Level 3 | Commodity fixed forwards
Derivative assets:
Financial assets	0	0
Derivative liabilities:
Financial liabilities	0	0
Significant Unobservable Inputs Level 3 | Futures swaps and options
Derivative assets:
Financial assets	0	0
Derivative liabilities:
Financial liabilities	0	0
Significant Unobservable Inputs Level 3 | Commodity derivatives
Derivative assets:
Financial assets	0	0
Derivative liabilities:
Financial liabilities	0	0
Significant Unobservable Inputs Level 3 | Interest rate swaps
Derivative assets:
Financial assets	0	0
Derivative liabilities:
Financial liabilities	0	0
Significant Unobservable Inputs Level 3 | Other Assets
Derivative assets:
Financial assets	0
Fair Value Measurement
Derivative assets:
Financial assets	62,787	114,747
Derivative liabilities:
Financial liabilities	80,085	165,028
Contingent consideration	10,246	9,725
Fair Value Measurement | Commodity fixed forwards
Derivative assets:
Financial assets	14,209	11,502
Derivative liabilities:
Financial liabilities	42,175	61,195
Fair Value Measurement | Futures swaps and options
Derivative assets:
Financial assets	42,571	100,630
Derivative liabilities:
Financial liabilities	37,862	103,827
Fair Value Measurement | Commodity derivatives
Derivative assets:
Financial assets	56,780	112,132
Derivative liabilities:
Financial liabilities	80,037	165,022
Fair Value Measurement | Interest rate swaps
Derivative assets:
Financial assets	5,993	2,615
Derivative liabilities:
Financial liabilities	48	$ 6
Fair Value Measurement | Other Assets
Derivative assets:
Financial assets	$ 14

XML

Financial Instruments and Off-Balance Sheet Risk - Additional Information (Detail) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018 USD ($)	Sep. 30, 2017 USD ($)	Sep. 30, 2018 USD ($)	Sep. 30, 2017 USD ($)	Dec. 31, 2017 USD ($)
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Net fair value of financial instruments			$ 25.4
Interest rate swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (loss) on cash flow hedge ineffectiveness, net	$ 0.0	$ 0.0	0.0	$ 0.0
Unrealized gains, net of tax, expected to be reclassified to earnings	$ 1.9		$ 1.9
Coen Energy, LLC And Coen Transport, LLC
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Business combination, contingent consideration arrangements, range of outcomes, value, high					$ 12.0
Measurement Input, Discount Rate | Business Combination, Contingent Consideration
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Debt instrument, measurement input	0.070		0.070

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Financial Instruments and Off-Balance Sheet Risk - Summary of Offsetting Arrangements (Detail) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross amount of recognized assets	$ 62,787	$ 114,747
Financial Instruments, Assets	(37,423)	(86,493)
Cash Collateral Posted, Assets	0	(4,303)
Net Amount, Assets	25,364	23,951
Gross Amount of Recognized Liabilities	(80,085)	(165,028)
Financial Instruments, Liabilities	37,423	86,493
Cash Collateral Posted, Liabilities	10,121	20,975
Net Amount, Liabilities	(32,541)	(57,560)
Commodity derivatives
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross amount of recognized assets	56,780	112,132
Financial Instruments, Assets	(37,423)	(86,493)
Cash Collateral Posted, Assets	0	(4,303)
Net Amount, Assets	19,357	21,336
Gross Amount of Recognized Liabilities	(80,037)	(165,022)
Financial Instruments, Liabilities	37,423	86,493
Cash Collateral Posted, Liabilities	10,121	20,975
Net Amount, Liabilities	(32,493)	(57,554)
Interest rate swaps
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross amount of recognized assets	5,993	2,615
Financial Instruments, Assets	0	0
Cash Collateral Posted, Assets	0	0
Net Amount, Assets	5,993	2,615
Gross Amount of Recognized Liabilities	(48)	(6)
Financial Instruments, Liabilities	0	0
Cash Collateral Posted, Liabilities	0	0
Net Amount, Liabilities	(48)	$ (6)
Other Assets
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gross amount of recognized assets	14
Financial Instruments, Assets	0
Cash Collateral Posted, Assets	0
Net Amount, Assets	$ 14

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Financial Instruments and Off-Balance Sheet Risk - Summary of Realized and Unrealized Gains (Losses) on Derivative Instruments for Commodity Risk Management (Detail) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Realized and unrealized gains (losses) on derivative instruments	$ (5,157)	$ (18,189)	$ 859	$ 41,487
Refined products contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Realized and unrealized gains (losses) on derivative instruments	1,087	(17,281)	10,063	27,637
Natural gas contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Realized and unrealized gains (losses) on derivative instruments	$ (6,244)	$ (908)	$ (9,204)	$ 13,850

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Financial Instruments and Off-Balance Sheet Risk - Schedule of Gross Volume of Commodity Derivative Instruments Outstanding (Detail) bbl in Thousands, MMBTU in Thousands	9 Months Ended	12 Months Ended
	Sep. 30, 2018 USD ($) MMBTU bbl	Dec. 31, 2017 MMBTU bbl
Long | Refined products contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gross volume, refined products (in barrels) | bbl	4,552	9,255
Long | Natural gas contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gross volume, natural gas (in millions of BTUs) | MMBTU	126,453	133,532
Short | Refined products contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gross volume, refined products (in barrels) | bbl	6,837	13,487
Short | Natural gas contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gross volume, natural gas (in millions of BTUs) | MMBTU	71,121	72,074
Cash Flow Hedging | Interest Rate Swaps Ending January 2019 | Designated as Hedging Instrument
Investment Derivative, Notional Amount [Abstract]
Notional amount of interest rate swap agreements	$ 275,000,000
Cash Flow Hedging | Interest Rate Swaps Ending January 2020 | Designated as Hedging Instrument
Investment Derivative, Notional Amount [Abstract]
Notional amount of interest rate swap agreements	300,000,000
Cash Flow Hedging | Interest Rate Swaps Ending January 2021 | Designated as Hedging Instrument
Investment Derivative, Notional Amount [Abstract]
Notional amount of interest rate swap agreements	300,000,000
Cash Flow Hedging | Interest Rate Swaps Ending January 2022 | Designated as Hedging Instrument
Investment Derivative, Notional Amount [Abstract]
Notional amount of interest rate swap agreements	300,000,000
Cash Flow Hedging | Interest Rate Swaps Ending January 2023 | Designated as Hedging Instrument
Investment Derivative, Notional Amount [Abstract]
Notional amount of interest rate swap agreements	$ 250,000,000

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Financial Instruments and Off-Balance Sheet Risk - Level 3 Liabilities Reconciliation (Details) - Business Combination, Contingent Consideration - Fair Value, Inputs, Level 3 $ in Thousands	9 Months Ended
	Sep. 30, 2018 USD ($)
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Contingent consideration - December 31, 2017	$ 9,725
Change in estimated fair value	521
Contingent consideration - September 30, 2018	$ 10,246

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Commitments and Contingencies - Commitments and Contingencies - Narrative (Details) $ in Millions	Sep. 30, 2018 USD ($)
Commitments and Contingencies Disclosure [Abstract]
Import tax, penalty, and interest	$ 3.5
Import tax	$ 7.3
Import tax, penalty, and interest percentage	15.00%

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Equity and Equity-Based Compensation - Additional Information (Detail) - USD ($) $ in Thousands		1 Months Ended	3 Months Ended		9 Months Ended		12 Months Ended
	Dec. 31, 2017	Jan. 31, 2018	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unit-based compensation recorded in unitholders' equity					$ (91)	$ 1,688
Unit-based compensation					$ (91)		$ 2,274
Phantom Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting period					3 years
Unit-based compensation recorded in unitholders' equity			$ (300)	$ (200)	$ (100)	$ 1,700
Unrecognized compensation cost related to performance-based phantom unit awards			$ 3,500		$ 3,500
Phantom Units (OCF-based)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting period					3 years
Minimum | Phantom Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage range of units granted					0.00%
Minimum | Phantom Units (OCF-based)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage range of units granted					0.00%
Maximum | Phantom Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage range of units granted					200.00%
Maximum | Phantom Units (OCF-based)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage range of units granted					200.00%
Weighted Average | Phantom Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Employee service share-based compensation, nonvested awards, compensation not yet recognized, share-based awards other than options, weighted-average recognition period					14 months
Common Unitholders - Public | Phantom Share Units (PSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage range of units granted	195.50%
Share-based compensation arrangement by share-based payment award, equity instruments other than options, vested in period		271,748			174,397		89,315
Unit-based compensation		$ 7,000
Share-based compensation arrangement by share-based payment award, equity instruments other than options, vested in period, withheld for taxes		97,351

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Equity and Equity-Based Compensation - Summary of Partnership's Unit Awards Subject to Vesting (Detail)	9 Months Ended
	Sep. 30, 2018 $ / shares shares
2018
Units
Nonvested, beginning (in shares) | shares	0
Granted (in shares) | shares	143,981
Forfeited (in shares) | shares	(5,460)
Vested (in shares) | shares	0
Nonvested, ending (in shares) | shares	138,521
Weighted Average Grant Date Fair Value (per unit)
Weighted-average grant date fair value, nonvested units, beginning (in dollars per share) | $ / shares	$ 0.00
Weighted-average grant date fair value, granted units (in dollars per share) | $ / shares	23.30
Weighted-average grant date fair value, forfeited units (in dollars per share) | $ / shares	(23.30)
Weighted-average grant date fair value, vested (in dollars per share) | $ / shares	0.00
Weighted-average grant date fair value, nonvested units, ending (in dollars per share) | $ / shares	$ 23.30
2017
Units
Nonvested, beginning (in shares) | shares	131,000
Granted (in shares) | shares	0
Forfeited (in shares) | shares	(3,208)
Vested (in shares) | shares	0
Nonvested, ending (in shares) | shares	127,792
Weighted Average Grant Date Fair Value (per unit)
Weighted-average grant date fair value, nonvested units, beginning (in dollars per share) | $ / shares	$ 26.96
Weighted-average grant date fair value, granted units (in dollars per share) | $ / shares	0.00
Weighted-average grant date fair value, forfeited units (in dollars per share) | $ / shares	(26.95)
Weighted-average grant date fair value, vested (in dollars per share) | $ / shares	0.00
Weighted-average grant date fair value, nonvested units, ending (in dollars per share) | $ / shares	$ 26.96
2016
Units
Nonvested, beginning (in shares) | shares	163,900
Granted (in shares) | shares	0
Forfeited (in shares) | shares	(1,202)
Vested (in shares) | shares	0
Nonvested, ending (in shares) | shares	162,698
Weighted Average Grant Date Fair Value (per unit)
Weighted-average grant date fair value, nonvested units, beginning (in dollars per share) | $ / shares	$ 17.52
Weighted-average grant date fair value, granted units (in dollars per share) | $ / shares	0.00
Weighted-average grant date fair value, forfeited units (in dollars per share) | $ / shares	(17.52)
Weighted-average grant date fair value, vested (in dollars per share) | $ / shares	0.00
Weighted-average grant date fair value, nonvested units, ending (in dollars per share) | $ / shares	$ 17.52

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Equity and Equity-Based Compensation - Schedule of Changes in Partnership's Units (Detail) - shares	1 Months Ended	9 Months Ended	12 Months Ended
	Jan. 31, 2018	Sep. 30, 2018	Dec. 31, 2017
Common Unitholders - Public
Share-based Compensation Arrangement by Share-based Payment Award [Roll Forward]
Beginning balance (in shares)	10,446,539	10,446,539	9,207,473
Ending balance (in shares)		10,620,936	10,446,539
Common Unitholders - Public | Employee Bonus
Share-based Compensation Arrangement by Share-based Payment Award [Roll Forward]
Units issued (in shares)			8,840
Common Unitholders - Public | Directors
Share-based Compensation Arrangement by Share-based Payment Award [Roll Forward]
Units issued (in shares)			9,360
Common Unitholders - Public | Phantom Share Units (PSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Roll Forward]
Units issued (in shares)	271,748	174,397	89,315
Common Unitholders - Affiliated
Share-based Compensation Arrangement by Share-based Payment Award [Roll Forward]
Beginning balance (in shares)	12,106,348	12,106,348	2,034,378
Partners' capital account, units, converted (in shares)			10,071,970
Ending balance (in shares)		12,106,348	12,106,348
Common Unitholders - Affiliated | Phantom Share Units (PSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Roll Forward]
Units issued (in shares)		0
Subordinated Unitholders - Affiliated
Share-based Compensation Arrangement by Share-based Payment Award [Roll Forward]
Beginning balance (in shares)	0	0	10,071,970
Partners' capital account, units, converted (in shares)			(10,071,970)
Ending balance (in shares)		0	0
Carbo Industries | Common Unitholders - Public
Share-based Compensation Arrangement by Share-based Payment Award [Roll Forward]
Units issued (in shares)			1,131,551

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Earnings Per Unit - Summary of Weighted Average Common Units Outstanding (Detail) - shares	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Earnings Per Share [Abstract]
Weighted average limited partner common units - basic (in shares)	22,727,284	22,543,527	22,726,645	22,093,578
Dilutive effect of unvested restricted and phantom units (in shares)	0	0	40,080	274,854
Weighted average limited partner common units - dilutive (in shares)	22,727,284	22,543,527	22,766,725	22,368,432

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Partnership Distributions - Schedule of Incentive Distribution Amounts (Detail) - USD ($) $ / shares in Units, $ in Thousands					3 Months Ended		9 Months Ended
	Oct. 26, 2018	Aug. 10, 2018	May 18, 2018	Feb. 12, 2018	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Cash distributed (in dollars per share)		$ 0.6675	$ 0.6525	$ 0.6375
Cash distributed		$ 17,225	$ 16,544	$ 17,622
Distribution declared per unit (in dollars per share)					$ 0.6675	$ 0.6225	$ 1.9875	$ 1.8225
Common
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Cash distributed		15,170	14,830	14,489
IDR
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Cash distributed		2,055	1,714	1,373
DER
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Cash distributed		$ 0	$ 0	$ 1,760
Subsequent event
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Distribution declared per unit (in dollars per share)	$ 0.6675
Distribution made to limited partner, cash distributions declared	$ 17,200
IDR | Subsequent event
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Distribution made to limited partner, cash distributions declared	$ 2,100