Sprague Resources LP - Quarter Report: 2017 March (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q



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

For the quarterly period ended March 31, 2017



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

Indicated by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulations S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post 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 (Do not check if a smaller reporting company)	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 22,543,527 common units outstanding as of May 1, 2017.

Table of Contents



		Page
PART I—FINANCIAL INFORMATION

Item 1.	Financial Statements:
	Condensed Consolidated Balance Sheets as of March 31, 2017 (unaudited) and December 31, 2016	1
	Unaudited Condensed Consolidated Statements of Operations for the three months ended March 31, 2017 and March 31, 2016	2
	Unaudited Condensed Consolidated Statements of Comprehensive Income for the three months ended March 31, 2017 and March 31, 2016	3
	Unaudited Condensed Consolidated Statement of Unitholders’ Equity (Deficit) for the three months ended March 31, 2017	4
	Unaudited Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2017 and March 31, 2016	5
	Notes to Unaudited Condensed Consolidated Financial Statements	6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	20
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	34
Item 4.	Controls and Procedures	37

PART II—OTHER INFORMATION

Item 1.	Legal Proceedings	38
Item 1A.	Risk Factors	38
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	38
Item 3.	Defaults Upon Senior Securities	38
Item 4.	Mine Safety Disclosures	38
Item 5.	Other Information	38
Item 6.	Exhibits	39
Signatures		40

Table of Contents

Part I – FINANCIAL INFORMATION

Item 1 — Condensed Consolidated Financial Statements

Sprague Resources LP

Condensed Consolidated Balance Sheets

(in thousands except units)



	March 31, 2017			December 31, 2016
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	14,506		$	2,682
Accounts receivable, net	196,466			221,954
Inventories	224,288			318,899
Fair value of derivative assets	64,030			66,858
Other current assets	32,341			43,316
Total current assets	531,631			653,709
Property, plant and equipment, net	257,921			251,101
Intangibles, net	22,167			23,446
Other assets, net	68,533			13,668
Goodwill	70,550			70,550
Total assets	$	950,802		$	1,012,474
Liabilities and unitholders’ equity
Current liabilities:
Accounts payable	$	81,600		$	138,358
Accrued liabilities	52,671			48,323
Fair value of derivative liabilities	47,251			95,339
Due to General Partner	9,581			14,218
Current portion of working capital facilities	92,516			153,603
Current portion of capital leases and other debt	1,311			1,358
Total current liabilities	284,930			451,199
Working capital facilities - less current portion	148,684			156,733
Acquisition facility	302,900			245,400
Capital leases and other debt - less current portion	3,883			4,165
Other liabilities	15,988			12,790
Due to General Partner	1,399			1,269
Deferred income taxes	16,751			15,481
Total liabilities	774,535			887,037
Commitments and contingencies (Note 9)
Unitholders’ equity:
Common unitholders - public (9,305,628 units and 9,207,473 units issued and outstanding, as of March 31, 2017 and December 31, 2016, respectively)	197,203			175,314
Common unitholders - affiliated (12,106,348 and 2,034,378 units issued and outstanding, as of March 31, 2017 and December 31, 2016, respectively)	(10,601		)	(4,518		)
Subordinated unitholders - affiliated (10,071,970 units issued and outstanding as of December 31, 2016)	—			(34,576		)
Accumulated other comprehensive loss, net of tax	(10,335		)	(10,783		)
Total unitholders’ equity	176,267			125,437
Total liabilities and unitholders’ equity	$	950,802		$	1,012,474

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

Table of Contents

Sprague Resources LP

Unaudited Condensed Consolidated Statements of Operations

(in thousands except unit and per unit amounts)



	Three Months Ended March 31,
	2017			2016
Net sales	$	917,807		$	722,907
Cost of products sold (exclusive of depreciation and amortization)	795,146			639,620
Operating expenses	16,832			16,829
Selling, general and administrative	26,289			24,130
Depreciation and amortization	5,932			5,031
Total operating costs and expenses	844,199			685,610
Operating income	73,608			37,297
Other income (expense)	64			(95		)
Interest income	84			127
Interest expense	(7,155		)	(6,983		)
Income before income taxes	66,601			30,346
Income tax provision	(2,102		)	(525		)
Net income	64,499			29,821
Incentive distributions declared	(742		)	(275		)
Limited partners’ interest in net income	$	63,757		$	29,546

Net income per limited partner unit:
Common - basic	$	2.98		$	1.39
Common - diluted	$	2.94		$	1.38
Subordinated - basic and diluted	N/A			$	1.39
Units used to compute net income per limited partner unit:
Common - basic	21,404,992			11,109,914
Common - diluted	21,718,627			11,249,460
Subordinated - basic and diluted	N/A			10,071,970

Distribution declared per common	$	0.5925		$	0.5325

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

Table of Contents

Sprague Resources LP

Unaudited Condensed Consolidated Statements of Comprehensive Income

(in thousands)



	Three Months Ended March 31,
	2017			2016
Net income	$	64,499		$	29,821
Other comprehensive income (loss), net of tax:
Unrealized gain (loss) on interest rate swaps
Net gain (loss) arising in the period	301			(1,054		)
Reclassification adjustment related to gains realized in income	120			396
Net change in unrealized gain (loss) on interest rate swaps	421			(658		)
Tax effect	(6		)	12
	415			(646		)
Foreign currency translation adjustment	33			34
Other comprehensive income (loss)	448			(612		)
Comprehensive income	$	64,947		$	29,209

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

Table of Contents

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, 2015	$	189,483		$	(1,370	)	$	(18,989	)	$	—		$	(11,639	)	$	157,485
Net income	3,815			847			4,192			1,312			—			10,166
Other comprehensive income	—			—			—			—			856			856
Unit-based compensation	1,820			404			2,000			—			—			4,224
Distributions paid	(19,894		)	(4,419		)	(21,878		)	(1,312		)	—			(47,503		)
Common units issued with annual bonus	1,748			392			1,939			—			—			4,079
Units withheld for employee tax obligations	(1,658		)	(372		)	(1,840		)	—			—			(3,870		)
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	27,760			36,142			—			597			—			64,499
Other comprehensive income	—			—			—			—			448			448
Unit-based compensation	373			486			—			—			—			859
Distributions paid	(5,715		)	(1,631		)	(5,817		)	(597		)	—			(13,760		)
Common units issued with annual bonus	161			210			—			—			—			371
Units withheld for employee tax obligations	(690		)	(897		)	—			—			—			(1,587		)
Balance at March 31, 2017	$	197,203		$	(10,601	)	$	—		$	—		$	(10,335	)	$	176,267

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

Table of Contents

Sprague Resources LP

Unaudited Condensed Consolidated Statements of Cash Flows

(in thousands)



	Three Months Ended March 31,
	2017			2016
Cash flows from operating activities
Net income	$	64,499		$	29,821
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization (includes amortization of deferred debt issuance costs)	6,947			5,957
Provision for doubtful accounts	(17		)	122
(Gain) loss on sale of assets	(66		)	79
Deferred income taxes	1,263			(81		)
Non-cash unit-based compensation	859			236
Changes in assets and liabilities:
Accounts receivable	25,505			(7,229		)
Inventories	95,537			89,708
Prepaid expenses and other assets	11,636			5,323
Fair value of commodity derivative instruments	(43,878		)	25,363
Due to General Partner and affiliates	(4,506		)	(5,356		)
Accounts payable, accrued liabilities and other	(52,367		)	(27,509		)
Net cash provided by operating activities	105,412			116,434
Cash flows from investing activities
Purchases of property, plant and equipment	(7,176		)	(3,622		)
Acquisitions, net of cash acquired	(58,910		)	(29,065		)
Proceeds from property insurance settlement and sale of assets	148			119
Net cash used in investing activities	(65,938		)	(32,568		)
Cash flows from financing activities
Net payments under credit agreements	(11,743		)	(89,008		)
Payments on capital lease liabilities and term debt	(270		)	(251		)
Payments on long-term terminal obligations	(122		)	(78		)
Debt issue costs	(189		)	(2,092		)
Distributions to unitholders	(13,760		)	(11,361		)
Foreign exchange on capital lease obligations	—			64
Units withheld for employee tax obligations	(1,587		)	(3,870		)
Net cash used in financing activities	(27,671		)	(106,596		)
Effect of exchange rate changes on cash balances held in foreign currencies	21			25
Net change in cash and cash equivalents	11,824			(22,705		)
Cash and cash equivalents, beginning of period	2,682			30,974
Cash and cash equivalents, end of period	$	14,506		$	8,269
Supplemental disclosure of cash flow information
Cash paid for interest	$	5,933		$	5,825
Cash paid for taxes	$	922		$	153

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

Table of Contents

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 to engage in the purchase, storage, distribution and sale of refined products and natural gas, and to provide 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 20 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, gasoline and asphalt (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 in the Northeast and Mid-Atlantic United States. The Partnership purchases the natural gas it sells from natural gas producers and trading companies. The materials handling segment offloads, stores and prepares for delivery a variety of customer-owned products, including asphalt, clay slurry, salt, gypsum, crude oil, residual fuel oil, coal, petroleum coke, caustic soda, tallow, pulp and heavy equipment. The Partnership’s other operations include the purchase and distribution of coal, certain commercial trucking activities and the heating equipment service business.

As of March 31, 2017, the Parent, through its ownership of Sprague Holdings, owns 12,106,348 common units representing an aggregate of 57% 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%, 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 partnership units that it owns. See Notes 11 and 12.

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, 2016 as filed with the SEC on March 10, 2017 (the “2016 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 revenues and expenses in the income statement. Actual results could differ from those estimates. Among the estimates made by management are asset valuations, the fair value of derivative assets and liabilities, environmental, and legal obligations.

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 2016 Annual Report, and are the same as are used in preparing these unaudited interim condensed consolidated financial statements.

Table of Contents

The condensed consolidated financial statements included herein reflect all normal and recurring adjustments which, in the opinion of management, are necessary for a fair presentation of the Partnership’s consolidated financial position at March 31, 2017 and December 31, 2016 and the consolidated results of operations and cash flows for the three months ended March 31, 2017 and 2016, respectively. 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

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), which clarifies 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 adoption of this new guidance is not expected to have a material impact on the Partnership's consolidated financial statements.

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. The Partnership has not yet adopted the provisions of this ASU, which 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. Early application is permitted, including adoption in an interim period. The adoption of this new guidance is not expected to have a material impact on the Partnership's consolidated statement of cash flows.

In March 2016, the FASB issued ASU 2016-09 Compensation- Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting, which addresses areas for simplification involving several aspects of the accounting for share-based payment transactions including, among other things, income tax consequences of excess benefits and deficiencies, classification of awards as either equity or liabilities, classification on the statement of cash flows, and the use of forfeiture estimates. The Partnership adopted the provisions of this ASU in 2017, which did not have a material impact to the Partnership's consolidated financial statements.

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. Under the new guidance, lessor accounting is largely unchanged. This ASU is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early application is permitted. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The modified retrospective approach would not require any transition accounting for leases that expired before the earliest comparative period presented. Lessees and lessors may not apply a full retrospective transition approach. The Partnership is currently evaluating the impact of this new standard on the consolidated financial statements.

In July 2015, the FASB issued ASU 2015-11, Simplifying the Measurement of Inventory, which requires that inventory within the scope of the guidance be measured at the lower of cost or net realizable value. The Partnership adopted the provisions of this ASU in 2017, which did not have a material impact to the Partnership's consolidated financial statements.

Table of Contents

In May 2014, the FASB issued ASU 2014-9, 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 has issued several ASUs subsequent to ASU 2014-9 in order 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 Partnership has reviewed and gained an understanding of the new revenue recognition accounting guidance, has completed a revenue stream scoping process and is currently evaluating the provisions of the standard by working with business segment representatives to evaluate any necessary changes to business processes, systems and controls. In addition, the Partnership is continuing to review its contracts and documentation. The Partnership currently expects to adopt this guidance on January 1, 2018, using the modified retrospective approach, under which the cumulative effect of initially applying the new guidance is recognized as an adjustment to the opening balance of unitholders' equity, and has not yet determined the effect of the update on the Partnership’s consolidated financial statements.

2. Business Combinations

Recent Acquisitions

During the month of February 2017, the Partnership completed three business acquisitions as described below. Allocations of the preliminary purchase price to the assets acquired and liabilities assumed have been made to record, where applicable, inventory, derivative assets and liabilities and natural gas transportation assets and liabilities. The Partnership is gathering information to complete the remaining allocations which is expected to be finalized during 2017 which will include allocations to property, plant and equipment, identifiable intangible assets such as customer relationships and non-compete agreements as well as to goodwill. The unallocated portion of the acquisitions is included in Other assets, net in the Condensed Consolidated Balance Sheet at March 31, 2017. The final allocations and resulting effect on income from operations may differ from these preliminary amounts. In connection with these transactions, the Partnership recognized $0.3 million of acquisition related costs that were expensed and are included in selling, general and administrative expense.

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, is subject to adjustment, and was financed with borrowings under the Partnership's 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 preliminary estimated fair values of the assets acquired and liabilities assumed:



Preliminary Allocation
Derivative assets	$	10,220
Other current assets	286
Natural gas transportation assets	1,493
Derivative liabilities	(9,704		)
Natural gas transportation liabilities	(1,047		)
Net assets remaining to be allocated	15,005
Net assets acquired	$	16,253

Table of Contents

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, is subject to adjustments, and was financed with borrowings under the Partnership's credit agreement. The purchase consists of two pipeline-supplied distillate terminals and one distillate storage facility with a combined capacity of 295,000 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 preliminary estimated fair values of the assets acquired and liabilities assumed:



Preliminary Allocation
Inventories	$	632
Derivative assets	678
Other current asset	7
Derivative liabilities	(648		)
Net assets remaining to be allocated	20,000
Net assets acquired	$	20,669

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, is subject to adjustments, and was financed with borrowings under the Partnership's 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.

3. Accumulated Other Comprehensive Loss, Net of Tax

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



	March 31, 2017			December 31, 2016
Fair value of interest rate swaps, net of tax	$	1,306		$	891
Cumulative foreign currency translation adjustment	(11,641		)	(11,674		)
Accumulated other comprehensive loss, net of tax	$	(10,335	)	$	(10,783	)

4. Inventories



	March 31, 2017		December 31, 2016
Petroleum and related products	$	213,440	$	305,827
Asphalt	8,226		7,089
Coal	2,014		3,149
Natural gas	608		2,834
Inventories	$	224,288	$	318,899

Table of Contents

5. Credit Agreement



	March 31, 2017			December 31, 2016
Working capital facilities	$	241,200		$	310,336
Acquisition facility	302,900			245,400
Total credit agreement	544,100			555,736
Less: current portion of working capital facilities	(92,516		)	(153,603		)
Long-term portion	$	451,584		$	402,133

On March 10, 2016, Sprague Resources LLC, the operating company of the Partnership and Kildair Service ULC ("Kildair") entered into an amendment to its amended and restated revolving credit agreement (the “Credit Agreement”) that matures on December 9, 2019. Obligations under the Credit Agreement are secured by substantially all of the assets of the Partnership and its subsidiaries. As of March 31, 2017, the revolving credit facilities under the Credit Agreement contained, among other items, the following:


•	U.S. dollar revolving working capital facility of up to $1.0 billion to be used for working capital loans and letters of credit in the principal amount equal to the lesser of the Partnership’s borrowing base and $1.0 billion;


•	Multicurrency revolving working capital facility of up to $120.0 million to be used by Kildair for working capital loans and letters of credit in the principal amount equal to the lesser of Kildair’s borrowing base and $120.0 million;


•	Revolving acquisition facility of up to $550.0 million 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, the U.S. dollar or multicurrency revolving working capital facilities may be increased by $200.0 million. Additionally, subject to certain conditions, the revolving acquisition facility may be increased by $200.0 million.

On April 27, 2017, the Partnership entered into an agreement to amend the Credit Agreement to extend the maturity through April 27, 2021, reduce the U.S. dollar working capital facility from $1.0 billion to $950.0 million, reduce the multicurrency working capital facility from $120.0 million to $100.0 million, reduce interest rates under certain leverage ratio scenarios, as well as make other modifications. See Note 13 - Subsequent Events.

Indebtedness under the Credit Agreement bears interest, at the Partnership’s option, at a rate per annum equal to either the Eurocurrency Base 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 an alternate rate plus a specified margin.

For the U.S. dollar working capital facility and the acquisition facility, the alternate rate is the Base Rate which is the higher of (a) the U.S. Prime Rate as in effect from time to time, (b) the Federal Funds 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 the Canadian dollar working capital facility, the alternate rate is the Prime Rate which is the higher of (a) the Canadian Prime Rate as in effect from time to time and (b) the one-month Eurocurrency Rate for U.S. dollars as in effect from time to time plus 1.00%.

The working capital facilities are subject to borrowing base reporting and as of March 31, 2017 and December 31, 2016, had a borrowing base of $403.6 million and $525.4 million, respectively. As of March 31, 2017 and December 31, 2016, outstanding letters of credit were $11.6 million and $31.6 million, respectively. As of March 31, 2017, excess availability under the working capital facilities was $150.8 million and excess availability under the acquisition facilities was $247.1 million.

The weighted average interest rate was 3.8% and 3.4% at March 31, 2017 and December 31, 2016, respectively. No amounts are due under the Credit Agreement until the maturity date, however, the current portion of the credit agreement at March 31, 2017 and December 31, 2016 represents the amounts of the working capital facility intended to be repaid during the following twelve month period.

Table of Contents

The Credit Agreement contains certain restrictions and covenants among which are a minimum level of net working capital, fixed charge coverage and debt leverage ratios and limitations on the incurrence of indebtedness. The Credit Agreement limits the Partnership’s ability to make distributions in the event of a default as defined in the Credit Agreement. As of March 31, 2017, the Partnership was in compliance with these covenants.

6. 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 $27.5 million and $25.5 million for the three months ended March 31, 2017 and 2016, respectively. Through the General Partner, the Partnership also participates in the Parent’s pension and other post-retirement benefits. At March 31, 2017 and December 31, 2016, total amounts due to the General Partner with respect to these benefits and overhead costs were $11.0 million and $15.5 million, respectively.

7. Segment Reporting

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

The Partnership’s refined products 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, large industrial companies, real estate management companies, hospitals and educational institutions.

The Partnership’s natural gas segment purchases natural gas from natural gas producers and trading companies and sells and distributes natural gas to commercial and industrial customers primarily in the Northeast and Mid-Atlantic United States.

The Partnership’s materials handling segment offloads, stores, and/or prepares for delivery a variety of customer-owned products, including asphalt, clay slurry, salt, gypsum, crude oil, residual fuel oil, coal, petroleum coke, caustic soda, tallow, pulp and heavy equipment. These services are fee-based activities which are generally conducted under multi-year agreements.

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

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

The Partnership had no single customer that accounted for more than 10% of total net sales for the three months ended March 31, 2017 and 2016, respectively. The Partnership’s foreign sales, primarily sales of refined products, asphalt and natural gas to its customers in Canada, were $46.2 million and $33.6 million for the three months ended March 31, 2017 and 2016, respectively.

Table of Contents

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



	Three Months Ended March 31,
	2017			2016

Net sales:
Refined products	$	781,590		$	589,944
Natural gas	119,666			115,619
Materials handling	9,925			11,391
Other operations	6,626			5,953
Net sales	$	917,807		$	722,907
Adjusted gross margin (1):
Refined products	$	39,478		$	41,642
Natural gas	38,590			31,122
Materials handling	9,925			11,392
Other operations	2,373			2,298
Adjusted gross margin	90,366			86,454
Reconciliation to operating (loss) income (2):
Add: unrealized gain (loss) on inventory derivatives (3)	24,508			(3,304		)
Add: unrealized (loss) gain on prepaid forward contract derivatives (4)	(27		)	481
Add: unrealized gain (loss) on natural gas transportation contracts (5)	7,814			(344		)
Operating costs and expenses not allocated to operating segments:
Operating expenses	(16,832		)	(16,829		)
Selling, general and administrative	(26,289		)	(24,130		)
Depreciation and amortization	(5,932		)	(5,031		)
Operating income	73,608			37,297
Other income (expense)	64			(95		)
Interest income	84			127
Interest expense	(7,155		)	(6,983		)
Income tax provision	(2,102		)	(525		)
Net income	$	64,499		$	29,821

(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 hedging gains and losses with regard to refined products and natural gas inventory derivatives, prepaid forward contract derivatives 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 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 hedging gain (loss) on prepaid forward contract derivatives 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.

Table of Contents

(5)

The unrealized hedging 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.

At March 31, 2017, goodwill recorded for the refined products, natural gas, materials handling and other operations segments amounted to $36.6 million, $25.9 million, $6.9 million and $1.2 million, respectively. The Partnership expects additional goodwill to be recorded once the allocations of the business combinations entered into in February 2017 are finalized. See Note 2 - Business Combinations.

8. Financial Instruments and Off-Balance Sheet Risk

As of March 31, 2017 and December 31, 2016, the carrying amounts of cash, cash equivalents and accounts receivable approximated fair value because of the short maturity of these instruments. As of March 31, 2017 and December 31, 2016, 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. As of March 31, 2017 and December 31, 2016, the carrying value of the Partnership’s debt approximated fair value due to the variable interest nature of these instruments.

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. 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 March 31, 2017 will settle prior to September 30, 2018.

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.

Table of Contents

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 does not offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) against the fair value of derivative instruments executed with the same counterparty under the same master netting arrangement. The Partnership had no right to reclaim or obligation to return cash collateral as of March 31, 2017 and December 31, 2016.

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



	As of March 31, 2017
	Fair Value Measurement		Quoted Prices in Active Markets Level 1		Significant Other Observable Inputs Level 2		Significant Unobservable Inputs Level 3
Financial assets:
Commodity fixed forwards	$	61,884	$	—	$	61,884	$	—
Commodity swaps and options	621		—		621		—
Commodity derivatives	62,505		—		62,505		—
Interest rate swaps	1,518		—		1,518		—
Other	7		—		7		—
Total	$	64,030	$	—	$	64,030	$	—
Financial liabilities:
Commodity fixed forwards	$	46,846	$	—	$	46,846	$	—
Commodity swaps and options	212		—		212		—
Commodity derivatives	47,058		—		47,058		—
Interest rate swaps	193		—		193		—
Total	$	47,251	$	—	$	47,251	$	—

Table of Contents



	As of December 31, 2016
	Fair Value Measurement		Quoted Prices in Active Markets Level 1		Significant Other Observable Inputs Level 2		Significant Unobservable Inputs Level 3
Financial assets:
Commodity fixed forwards	$	65,618	$	—	$	65,618	$	—
Commodity derivatives	65,618		—		65,618		—
Interest rate swaps	1,240		—		1,240		—
Total	$	66,858	$	—	$	66,858	$	—
Financial liabilities:
Commodity fixed forwards	$	94,875	$	—	$	94,875	$	—
Commodity swaps and options	103		—		103		—
Commodity derivatives	94,978		—		94,978		—
Interest rate swaps	336		—		336		—
Other	25		—		25		—
Total	$	95,339	$	—	$	95,339	$	—

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 $61.3 million at March 31, 2017. Information related to these offsetting arrangements is as follows:



	As of March 31, 2017
									Gross Amount Not Offset in the Balance Sheet
	Gross Amount of Recognized Assets/ Liabilities			Gross Amount Offset in the Balance Sheet		Amount of Assets/ Liabilities in the Balance Sheet			Financial Instruments			Cash Collateral Posted			Net Amount
Commodity derivative assets	$	62,505		$	—	$	62,505		$	(2,716	)	$	(15	)	$	59,774
Interest rate swap derivative assets	1,518			—		1,518			—			—			1,518
Other assets	7			—		7			—			—			7
Fair value of derivative assets	$	64,030		$	—	$	64,030		$	(2,716	)	$	(15	)	$	61,299

Commodity derivative liabilities	$	(47,058	)	$	—	$	(47,058	)	$	2,716		$	—		$	(44,342	)
Interest rate swap derivative liabilities	(193		)	—		(193		)	—			—			(193		)
Fair value of derivative liabilities	$	(47,251	)	$	—	$	(47,251	)	$	2,716		$	—		$	(44,535	)



	As of December 31, 2016
									Gross Amount Not Offset in the Balance Sheet
	Gross Amount of Recognized Assets/ Liabilities			Gross Amount Offset in the Balance Sheet		Amount of Assets/ Liabilities in the Balance Sheet			Financial Instruments			Cash Collateral Posted			Net Amount
Commodity derivative assets	$	65,618		$	—	$	65,618		$	(2,154	)	$	(209	)	$	63,255
Interest rate swap derivative assets	1,240			—		1,240			—			—			1,240
Fair value of derivative assets	$	66,858		$	—	$	66,858		$	(2,154	)	$	(209	)	$	64,495

Commodity derivative liabilities	$	(94,978	)	$	—	$	(94,978	)	$	2,154		$	—		$	(92,824	)
Interest rate swap derivative liabilities	(336		)	—		(336		)	—			—			(336		)
Other liabilities	(25		)	—		(25		)	—			—			(25		)
Fair value of derivative liabilities	$	(95,339	)	$	—	$	(95,339	)	$	2,154		$	—		$	(93,185	)

Table of Contents

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



	Three Months Ended March 31,
	2017		2016
Refined products contracts	$	33,567	$	33,033
Natural gas contracts	15,164		19,032
Total	$	48,731	$	52,065

There were no discretionary trading activities for the three months ended March 31, 2017 and 2016. The following table presents gross volume of commodity derivative instruments outstanding for the periods indicated:



	As of March 31, 2017				As of December 31, 2016
	Refined Products (Barrels)		Natural Gas (MMBTUs)		Refined Products (Barrels)		Natural Gas (MMBTUs)
Long contracts	6,871		117,959		9,882		131,240
Short contracts	(10,178	)	(69,577	)	(13,940	)	(76,556	)

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 March 31, 2017 were as follows:



Interest Rate Swap Agreements
Beginning	Ending	Notional Amount
September 2016	April 2017	$	25,000
January 2017	January 2018	$	225,000
January 2018	January 2019	$	200,000

There was no material ineffectiveness determined for the cash flow hedges for the three months ended March 31, 2017 and 2016.

The Partnership records unrealized gains and losses on its interest rate swaps as a component of accumulated other comprehensive loss, net of tax, which is reclassified to earnings as interest expense when the payments are made. As of March 31, 2017, the amount of unrealized gains, net of tax, expected to be reclassified to earnings during the following twelve-month period was $0.5 million.

9. Commitments and Contingencies

Legal, Environmental and Other Proceedings

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

Table of Contents

10. Equity and Equity-Based Compensation

Equity Awards - Annual Bonus Program

The board of directors of the General Partner has approved an annual bonus program which is provided to substantially all employees. Under this program bonuses for the majority of participants will be settled in cash with others receiving a combination of cash and common units. The Partnership records the expected bonus payment as a liability until a grant date has been established and awards finalized, which occurs in the first quarter of the year following the year for which the bonus is earned. Of the annual bonus accrued as of December 31, 2016, approximately $0.4 million was subsequently settled by issuing 13,465 common units in 2017 (market value at settlement of $0.4 million) with 4,625 units being withheld to satisfy tax withholding obligations.

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.

TUR-based Phantom Units

Phantom unit awards granted in 2015 and 2014, include a market condition criteria that considers the Partnership's total unitholder return ("TUR") over the vesting period, compared with the total unitholder return of a peer group of other master limited partnership energy companies over the same period. These awards are equity awards with both service and market-based conditions, which results in compensation cost being recognized over the requisite service period, provided that the requisite service period is fulfilled, regardless of when, if ever, the market based conditions are satisfied. The fair value of the TUR based phantom units was estimated at the date of grant based on a Monte Carlo model that estimates the most likely performance outcome based on the terms of the award. The key inputs in the model include the market price of the Partnership’s common units as of the valuation date, the historical volatility of the market price of the Partnership’s common units, the historical volatility of the market price of the common units or common stock of the peer companies and the correlation between changes in the market price of the Partnership’s common units and those of the peer companies. TUR-based phantom units issued in 2014 with a performance period ending as of December 31, 2016 vested at the 200% level and as a result 142,100 common units (vested market value of $3.9 million) were issued during January 2017 with 52,785 units being withheld to satisfy tax withholding obligations.

OCF-based Phantom Units

Phantom unit awards granted in 2017 and 2016 include a performance criteria that considers operating cash flow, as defined therein ("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 was 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.

Table of Contents

A summary of the Partnership’s unit awards subject to vesting during the three months ended March 31, 2017 is set forth below:



	2017 Phantom Units (OCF-based)					2016 Phantom Units (OCF-based)					2015 Phantom Units (TUR-based)
	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, 2016	—		$	—		166,900		$	17.52		141,000		$	31.58
Granted	131,027		26.60			—		$	—		—		$	—
Forfeited	(1,977	)	(26.60		)	(3,000	)	(17.52		)	(2,000	)	(31.58		)
Vested	—		—			—		—			—		—
Nonvested at March 31, 2017	129,050		$	26.60		163,900		$	17.52		139,000		$	31.58

Unit-based compensation recorded in unitholders’ equity for the three months ended March 31, 2017 and 2016 was $0.9 million and $1.0 million, respectively, and is included in selling, general and administrative expenses. Total unrecognized compensation cost related to performance-based phantom unit awards totaled $7.7 million as of March 31, 2017 which is expected to be recognized over a weighted average period of 20 months.

Equity - Changes in Partnership Units

Pursuant to the terms of the partnership agreement, upon payment of the cash distribution on February 14, 2017, and meeting certain distribution and performance tests, the subordination period for the Partnership's subordinated units expired and all subordinated units converted into common units on a one-for-one basis.

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



	Common Units		Subordinated Units
	Public	Sprague Holdings	Sprague Holdings
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 phantom and performance awards	89,315	—	—
Units issued in connection with employee bonus	8,840	—	—
Balance as of March 31, 2017	9,305,628	12,106,348	—

11. Earnings Per Unit

Earnings per unit applicable to limited partners (including subordinated unitholders) 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. 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.

In addition to the common and subordinated units, the Partnership has also identified the IDRs and unvested unit awards as participating securities and uses the two-class method when calculating the net income per unit applicable to limited partners, which is based on the weighted-average number of units outstanding during the period. Diluted earnings per unit includes the effects of potentially dilutive units on the Partnership’s common units, consisting of unvested unit awards. Basic and diluted earnings per unit applicable to subordinated limited partners are the same because there are no potentially dilutive subordinated units outstanding.

Table of Contents

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



	Three Months Ended March 31,
	2017	2016
Weighted average limited partner common units - basic	21,404,992	11,109,914
Dilutive effect of unvested restricted and phantom units	313,635	139,546
Weighted average limited partner common units - dilutive	21,718,627	11,249,460

All outstanding subordinated units converted to common units on February 16, 2017. Since the subordinated units did not share in the distribution of cash generated during the three months ended March 31, 2017, the Partnership did not allocate any earnings or loss to the subordinated unitholders. The following tables provide a reconciliation of net income and the assumed allocation of net income to the limited partners’ interest for purposes of computing net income per unit during periods prior to the conversion of the subordinated units:



	Three Months Ended March 31, 2016
	Common		Subordinated		IDR		Total
	(in thousands, except for per unit amounts)
Net income							$	29,821
Distributions declared	$	5,981	$	5,363	$	275	$	11,619
Assumed net income from operations after distributions	9,516		8,686		—		18,202
Assumed net income to be allocated	$	15,497	$	14,049	$	275	$	29,821
Income per unit - basic	$	1.39	$	1.39
Income per unit - diluted	$	1.38	$	1.39

12. Partnership Distributions

The Partnership agreement sets forth the calculation to be used to determine the amount and priority of cash distributions that the common and subordinated unitholders will receive as well as incentive distributions. Payments made in connection with DERs are recorded as a distribution.

Cash distributions for the periods indicated were as follows:



			Cash Distributed
For the Quarter Ended	Payment Date	Per Unit	Common		Subordinated		IDR		DER		Total
December 31, 2016	February 14, 2017	$0.5775	$	6,544	$	5,817	$	597	$	802	$	13,760
March 31, 2017 (1)	May 15, 2017	$0.5925	$	13,357	$	—	$	742	$	—	$	14,099


(1)	On April 27, 2017, the Partnership declared a cash distribution of $0.5925 per unit to be paid to unitholders of record on May 8, 2017.

13. Subsequent Events

Acquisition of 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 $71.1 million and consisted of $10.0 million in cash that was financed through borrowings under the credit facility, an obligation to pay $38.2 million over a ten year period (estimated net present value of $26.6 million), $31.4 million in unregistered common units, plus payments for inventory and other current assets of $3.1 million. The Carbo terminals have a combined gasoline, ethanol and distillate storage capacity of 157,000 barrels and are supplied primarily by pipeline with the ability to also accept product deliveries by barge and truck. The Partnership recognized $0.3 million of acquisition related costs that were expensed and are included in selling, general and administrative expense.

Amendment to Credit Agreement

On April 27, 2017, the Partnership entered into an agreement to amend the Credit Agreement to extend the maturity through April 27, 2021, reduce the working capital facility from $1.0 billion to $950.0 million, reduce the multicurrency working capital facility from $120.0 million to $100.0 million, reduce interest rates under certain leverage ratio scenarios, as well as make other modifications.

Table of Contents



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 to realize the anticipated financial 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, 2016, as filed with the U.S. Securities and Exchange Commission (“SEC”) on March 10, 2017 (the “2016 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.

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the Partnership’s financial statements and related notes thereto as of and for the three months ended March 31, 2017 contained elsewhere in this Quarterly Report and the audited financial statements and related notes included in our 2016 Annual Report.

Table of Contents

Overview

We are a Delaware limited partnership formed in June 2011 by Sprague Holdings and our General Partner to engage in the purchase, storage, distribution and sale of refined products and natural gas, and to 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, “we,” “us,” “our” mean Sprague Resources LP and, where the context requires, includes our subsidiaries.

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 20 refined products and materials handling terminals strategically located throughout the Northeast United States and in Quebec, Canada that have a combined storage capacity of 14.4 million barrels for refined products and other liquid materials, as well as 2.0 million square feet of materials handling capacity. We also have an aggregate of 2.1 million barrels of additional storage capacity attributable to 48 storage tanks not currently in service. These tanks are not necessary for the operation of our business at current levels. In the event that such additional capacity were desired, additional time and capital would be required to bring any of such storage tanks into service. Furthermore, we have access to more than 50 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 “Segment Reporting” included under Note 7 to our Condensed Consolidated Financial Statements for a presentation of financial results by reportable segment and see 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, gasoline and asphalt (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 more than 1,000 home heating oil retailers and diesel fuel and gasoline resellers. Our commercial customers include federal and state agencies, municipalities, regional transit authorities, large industrial companies, real estate management companies, hospitals, educational institutions and asphalt paving companies. For the three months ended March 31, 2017 and 2016, we sold 472.7 million and 477.4 million gallons, respectively.

In our natural gas segment we purchase, sell and distribute natural gas to approximately 18,000 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. For three months ended March 31, 2017 and 2016, we sold 20.2 million and 18.8 million Bcf, respectively.

Our materials handling segment is a fee-based business and is generally conducted under multi-year agreements. We offload, store and/or prepare for delivery a variety of customer-owned products, including asphalt, crude oil, clay slurry, salt, gypsum, coal, petroleum coke, caustic soda, tallow, pulp and heavy equipment. For the three months ended March 31, 2017 we offloaded, stored and/or prepared for delivery 0.6 million short tons of products and 75.3 million gallons of liquid materials. For the three months ended March 31, 2016, we offloaded, stored and/or prepared for delivery 0.6 million short tons of products and 75.4 million gallons of liquid materials.

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.

As of March 31, 2017, the Parent, through its ownership of Sprague Holdings, owns 12,106,348 common units representing an aggregate of 57% 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.

Table of Contents

Recent Developments

Conversion of Subordinated Units

Pursuant to the terms of our partnership agreement, upon payment of the cash distribution on February 14, 2017, and meeting certain distribution and performance tests, the subordination period for our subordinated units expired on February 16, 2017. At the expiration of the subordination period, all 10,071,970 subordinated units converted into common units on a one-for-one basis.

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, is subject to adjustments, 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, is subject to adjustment, 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 295,000 barrels, as well as L.E. Belcher’s associated wholesale and commercial fuels businesses.

Capital Terminal Acquisition

On February 10, 2017, we acquired the East Providence, Rhode Island refined product terminal of Capital Terminal Company (the “Capital Terminal”). Consideration paid was $22.0 million, is subject to adjustments, and was financed with borrowings under our credit facility. The terminal’s combined distillate storage capacity of just over 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 expect to invest approximately $8.0 million in 2017 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. We also expect to invest approximately $3.0 million in 2017 to optimize distillate storage between this newly acquired terminal and our existing terminal facility in Providence to allow for expanded materials handling capability in Providence, Rhode Island.

Carbo Terminal 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 $71.1 million and consisted of $10.0 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 $26.6 million), $31.4 million in unregistered common units, plus payments for inventory and other current assets of $3.1 million. The Carbo terminals have a combined gasoline, ethanol and distillate storage capacity of 157,000 barrels and are supplied primarily by pipeline with the ability to also accept product deliveries by barge and truck.

Amendment to Credit Agreement

On April 27, 2017, we entered into an agreement to amend the Credit Agreement to extend the maturity through April 27, 2021, reduce the U.S. dollar working capital facility from $1.0 billion to $950.0 million, reduce the multicurrency working capital facility from $120 million to $100 million, reduce interest rates under certain leverage ratio scenarios and made other modifications. See Note 13 - “Subsequent Events” to our Condensed Consolidated Financial Statements.

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.

Table of Contents

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 (described below), (2) operating expenses, (3) selling, general and administrative (or SG&A) expenses and (4) heating degree days.

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 unit holders.

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.

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;


•	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.

Table of Contents

Adjusted Gross Margin

Management trades, purchases, stores and sells energy commodities that experience market value fluctuations. To manage the Partnership’s underlying performance, including its physical and derivative positions, management utilizes adjusted gross margin. In determining adjusted gross margin, management adjusts its segment results for the impact of unrealized hedging 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 its 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 supplemental financial measures 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 alternatives to net income (loss) or operating income (loss) or any other measure of financial performance presented in accordance with GAAP.

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 "Segment Reporting" included under Note 7 to our Condensed Consolidated Financial Statements for a presentation of our financial results by reportable segment. Management evaluates our segment performance based on adjusted gross margin. Based on the way we manage our business, it is not reasonably possible for us to allocate the components of operating expenses, selling, general and administrative expenses and depreciation and amortization among the operating segments.

Operating Expenses

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

Selling, General and Administrative Expenses

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

Table of Contents

Heating Degree Days

A “degree day” is an industry measurement of temperature designed to evaluate energy demand and consumption. Degree days are based on how much the average temperature departs from a human comfort level of 65°F. Each degree of temperature above 65°F is counted as one cooling degree day, and each degree of temperature below 65°F is counted as one heating degree day. Degree days are accumulated over the course of a year and can be compared to a monthly or a long-term average (“normal”) to see if a month or a year was warmer or cooler than usual. Degree days are officially observed by the National Weather Service and archived by the National Climatic Data Center. For purposes of evaluating our results of operations, we use the normal heating degree day amount as reported by the NOAA/National Weather Service for the New England oil home heating region over the period of 1981-2011.

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 market, or LCM. 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 daily using 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.

Trends and Factors that Impact our Business

In addition to the other information set forth in this report, please refer to our 2016 Annual Report for a discussion of the trends and factors that impact our business.

Table of Contents

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 market. Please read “How Management Evaluates Our Results of Operations.” For a description of acquisition activity during the periods presented, please read "Business Combinations" included under Note 2 to our Condensed Consolidated Financial Statements.

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



	Three Months Ended March 31,						Increase/(Decrease)
	2017			2016			$			%
	($ in thousands)
Net sales	$	917,807		$	722,907		$	194,900		27	%
Cost of products sold (exclusive of depreciation and amortization)	795,146			639,620			155,526			24	%
Operating expenses	16,832			16,829			3			—	%
Selling, general and administrative	26,289			24,130			2,159			9	%
Depreciation and amortization	5,932			5,031			901			18	%
Total operating costs and expenses	844,199			685,610			158,589			23	%
Operating income	73,608			37,297			36,311			97	%
Other income (expense)	64			(95		)	159			(167	)%
Interest income	84			127			(43		)	(34	)%
Interest expense	(7,155		)	(6,983		)	(172		)	2	%
Income before income taxes	66,601			30,346			36,255			119	%
Income tax provision	(2,102		)	(525		)	(1,577		)	300	%
Net income	$	64,499		$	29,821		$	34,678		116	%

Analysis of Consolidated Operating Results

Net income was $64.5 million and $29.8 million for the three months ended March 31, 2017 and 2016, respectively and operating income was $73.6 million and $37.3 million for the three months ended March 31, 2017 and 2016, respectively. Operating results for the three months ended March 31, 2017 and 2016 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 $32.3 million and $(3.2) million, respectively. Excluding these unrealized items, operating income for the three months ended March 31, 2017 increased $0.8 million, or 2%, as compared to the three months ended March 31, 2016.

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

Table of Contents

Reconciliation to Adjusted Gross Margin, EBITDA and Adjusted EBITDA

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



	Three Months Ended March 31,
	2017			2016
Reconciliation of Operating Income to Adjusted Gross Margin:
Operating income	$	73,608		$	37,297
Operating costs and expenses not allocated to operating segments:
Operating expenses	16,832			16,829
Selling, general and administrative	26,289			24,130
Depreciation and amortization	5,932			5,031
Add: unrealized (gain) loss on inventory derivatives (1)	(24,508		)	3,304
Add: unrealized loss (gain) on prepaid forward contract derivatives (2)	27			(481		)
Add: unrealized (gain) loss on natural gas transportation contracts (3)	(7,814		)	344
Total adjusted gross margin (4):	$	90,366		$	86,454
Adjusted Gross Margin by Segment:
Refined products	$	39,478		$	41,642
Natural gas	38,590			31,122
Materials handling	9,925			11,392
Other operations	2,373			2,298
Total adjusted gross margin	$	90,366		$	86,454
Reconciliation of Net Income to Adjusted EBITDA
Net income	$	64,499		$	29,821
Add/(deduct):
Interest expense, net	7,071			6,856
Tax provision	2,102			525
Depreciation and amortization	5,932			5,031
EBITDA (4):	$	79,604		$	42,233
Add: unrealized (gain) loss on inventory derivatives (1)	(24,508		)	3,304
Add: unrealized loss (gain) on prepaid forward contract derivatives (2)	27			(481		)
Add: unrealized (gain) loss on natural gas transportation contracts (3)	(7,814		)	344
Adjusted EBITDA (4):	$	47,309		$	45,400
Other Data:
Normal heating degree days (5)	3,274			3,310
Actual heating degree days	3,031			2,922
Variance from normal heating degree days	(7		)%	(12		)%
Variance from prior period actual heating degree days	4		%	(25		)%

Table of Contents


(1)	Inventory is valued at the lower of cost or market. The fair value of the derivatives we use to economically hedge our inventory declines or appreciates in value as the value of the underlying inventory appreciates or declines, which creates unrealized hedging (losses) gains with respect to the derivatives that are included in net income.

(2)

The unrealized hedging gain (loss) on prepaid forward contract derivatives represents our 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 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.

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


(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)	As reported by the NOAA/National Weather Service for the New England oil home heating region over the period of 1981-2011.

Analysis of Operating Segments

Three Months Ended March 31, 2017 compared to Three Months Ended March 31, 2016



	Three Months Ended March 31,				Increase/(Decrease)
	2017		2016		$			%
	($ in thousands, except adjusted unit gross margin)
Volumes:
Refined products (gallons)	472,710		477,372		(4,662		)	(1	)%
Natural gas (MMBtus)	20,204		18,831		1,373			7	%
Materials handling (short tons)	581		637		(56		)	(9	)%
Materials handling (gallons)	75,264		75,390		(126		)	—	%
Net Sales:
Refined products	$	781,590	$	589,944	$	191,646		32	%
Natural gas	119,666		115,619		4,047			4	%
Materials handling	9,925		11,391		(1,466		)	(13	)%
Other operations	6,626		5,953		673			11	%
Total net sales	$	917,807	$	722,907	$	194,900		27	%
Adjusted Gross Margin:
Refined products	$	39,478	$	41,642	$	(2,164	)	(5	)%
Natural gas	38,590		31,122		7,468			24	%
Materials handling	9,925		11,392		(1,467		)	(13	)%
Other operations	2,373		2,298		75			3	%
Total adjusted gross margin	$	90,366	$	86,454	$	3,912		5	%
Adjusted Unit Gross Margin:
Refined products	$	0.084	$	0.087	$	(0.003	)	(3	)%
Natural gas	$	1.910	$	1.653	$	0.257		16	%

Table of Contents

Refined Products

Refined products net sales increased $191.6 million, or 32%, compared to the same period last year, primarily due to 34% increase in the average sales price given a higher energy price environment.

Refined products adjusted gross margin decreased $2.2 million, or 5%, compared to the first quarter of 2016, due to reduced unit margins, and to a lesser extent, lower volumes. Although the weather was modestly colder (4% increase in heating degree days) than the exceptionally warm conditions in the same period in 2016, the overall quarter was still substantially warmer than normal. In addition, the average temperatures were warmer than the same period last year during the higher demand periods of January and February, when unit margins on discretionary distillate volumes are typically under less pressure. Reflecting the warmer January and February of 2017 compared to January and February of 2016, only 64% of the total heating degree days for the first quarter of 2017 were contained in those two months compared to 73% in the same period last year and 72% based on normal heating degree days. Although overall volumes were down only modestly in the first quarter of 2017 compared to the same period in 2016, the weaker demand during the early part of the quarter as well as fewer requirements to interruptible power generators led to a well-supplied and competitive discretionary market. Also contributing to the reduced unit margins was less favorable conditions to supply and carry gasoline inventory. The purchase of the L.E. Belcher terminal and industrial and commercial fuels business at the beginning of February contributed about 2% to the total volume for the first quarter of 2017, helping to offset the volume decline.

Natural Gas

Natural gas net sales increased $4.0 million, or 4%, as compared to the same period last year due to a 7% gain in volumes, with average sales prices about 4% lower in the first quarter of 2017 compared to the same period in 2016. The volume gain was the result of the 2.0 MMBtu contribution from the Global natural gas acquisition at the beginning of February, with other volumes down 3% compared to last year.

Natural gas adjusted gross margin increased by $7.5 million, or 24%, compared to the same period last year, due to a combination of the higher volumes and a 16% gain in unit margin. The key contributor to the unit margin improvement was enhanced optimization of pipeline capacity.

Materials Handling

Materials handling net sales and adjusted gross margin both decreased $1.5 million, or 13%, compared to the same period last year primarily due to a reduction in windmill component handling. The first three months of 2017 experienced many more storm events than the same period last year leading to increased road salt requirements, partially offsetting the windmill component activity decline.

Other Operations

Net sales from other operations increased by $0.7 million, or 11%, compared to the same period last year primarily due to higher coal demand and prices, with adjusted gross margin increasing modestly by $0.1 million, or 3%.

Operating Costs and Expenses

Three Months Ended March 31, 2017 compared to Three Months Ended March 31, 2016



	Three Months Ended March 31,				Increase/(Decrease)
	2017		2016		$		%
	($ in thousands)
Operating expenses	$	16,832	$	16,829	$	3	—%
Selling, general and administrative	$	26,289	$	24,130	$	2,159	9%
Depreciation and amortization	$	5,932	$	5,031	$	901	18%
Interest expense, net	$	7,071	$	6,856	$	215	3%

Operating Expenses. Operating expenses for the first quarter of 2017 were comparable to the same period in 2016, reflecting $0.3 million of operating expenses at our Springfield and East Providence terminals acquired in February 2017, offset by a $0.5 million decrease in maintenance, insurance and utility expenses at our other terminals.

Table of Contents

Selling, General and Administrative Expenses. Selling, general and administrative expenses increased $2.2 million, or 9%, compared to the same period last year primarily as a result of an increase in employee related expenses of $2.3 million, including incentive compensation, and a $0.5 million increase of selling and administrative expenses related to the Global acquisition in February 2017. These increases were partially offset by $1.0 million of decreased professional fees.

Depreciation and Amortization. Depreciation and amortization increased $0.9 million, or 18%, for the first quarter of 2017 compared to the same period last year primarily as a result of the three acquisitions in February 2017.

Interest Expense, net. Interest expense, net increased $0.2 million, or 3%, primarily related to increased borrowings for the three acquisitions completed in February 2017.

Liquidity and Capital Resources

Liquidity

Our primary liquidity needs are to fund our working capital requirements, operating expenses, capital expenditures and quarterly distributions. Cash generated from operations, our borrowing capacity under our Credit Agreement (as defined below) and potential future issuances of additional partnership interests or debt securities are our primary sources of liquidity. At March 31, 2017, we had working capital of $246.7 million.

As of March 31, 2017, the undrawn borrowing capacity under the working capital facilities was $150.8 million and the undrawn borrowing capacity under the acquisition facility was $247.1 million. We enter our seasonal peak period during the fourth quarter of each year, during which inventory, accounts receivable and debt levels increase. As we move out of the winter season at the end of the first quarter of the following year, typically inventory is reduced, accounts receivable are collected and converted into cash and debt is paid down. During the three months ended March 31, 2017, the amount drawn under the working capital facilities of our Credit Agreement fluctuated from a low of $220.0 million to a high of $310.3 million.

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

Credit Agreement

On March 10, 2016, Sprague Operating Resources LLC, the operating company of the Partnership, Sprague Resources ULC and Kildair ULC ("Kildair") entered into an amendment to its amended and restated revolving credit agreement (the “Credit Agreement”). Capitalized terms used but not otherwise defined in this section entitled “Credit Agreement” are used as defined in the Credit Agreement. Obligations under the Credit Agreement are secured by substantially all of the assets of the Partnership and its subsidiaries. As of March 31, 2017, the Credit Agreement contained, among other items, the following:


•	A U.S. dollar revolving working capital facility of up to $1.0 billion to be used for working capital loans and letters of credit;


•	A multicurrency revolving working capital facility of up to $120.0 million to be used by Kildair for working capital loans and letters of credit;


•	A revolving acquisition facility of up to $550.0 million 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, the U.S. dollar and multicurrency revolving working capital facilities may be increased by $200.0 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 will bear interest, at the Partnership’s option, at a rate per annum equal to either 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 an alternate rate plus a specified margin.

Table of Contents

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 2.00% to 2.25% for loans bearing interest at the alternate Base Rate and from 3.00% 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.

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, among others: 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, a maximum consolidated senior secured leverage-to-EBITDA ratio. The Credit Agreement also limits our ability to incur debt, grant liens, make certain investments or acquisitions, dispose of assets, and incur additional indebtedness. The Partnership was in compliance with the covenants under the Credit Agreement at March 31, 2017.

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-accelerations, 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.

On April 27, 2017, Sprague Operating Resources LLC and Kildair Service ULC entered into an amendment to the Credit Agreement to extend the maturity of the Credit Agreement from December 9, 2019 to April 27, 2021, and, among other items the following revisions:


•	U.S. dollar revolving working capital facility used for working capital loans and letters of credit is reduced from $1.0 billion to $950.0 million;


•	Multicurrency revolving working capital facility used by Kildair for working capital loans and letters of credit is reduced from $120.0 million to $100.0 million;


•	The specified margin for the acquisition facility were reduced and now range from 2.25% to 3.25% for LIBOR loans and 1.25% to 2.25% for base rate loans;


•	Subject to certain conditions, the U.S. dollar or multicurrency revolving working capital facilities may be increased by $270.0 million (formerly $200.0 million).

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements.

Table of Contents

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. Maintenance capital expenditures represent 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. Expansion capital expenditures are 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 acquisitions.



	Capital Expenditures
	Expansion		Maintenance		Total
	($ in thousands)
Three Months Ended March 31,
2017	$	5,846	$	1,330	$	7,176
2016	$	2,170	$	1,452	$	3,622

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

Cash Flows



	Three Months Ended March 31,
	2017			2016
	($ in thousands)
Net cash provided by operating activities	$	105,412		$	116,434
Net cash used in investing activities	$	(65,938	)	$	(32,568	)
Net cash used in financing activities	$	(27,671	)	$	(106,596	)

Operating Activities

Net cash provided by operating activities for the three months ended March 31, 2017 was $105.4 million and was primarily driven by cash inflows as a result of a decrease of $95.5 million in inventories due to a seasonal reduction in inventory requirements, $64.5 million in net income and a decrease of $25.5 million in accounts receivable due to seasonal reduction in sales volume. These inflows were offset by cash outflows as a result of a reduction of $52.4 million in accounts payable and accrued liabilities primarily relating to the timing of invoice payments for product purchases and a reduction of $43.9 million net change in derivative instruments relating to the ratable liquidation of our fixed forward contracts as we came out of the peak season.

Net cash provided by operating activities for the three months ended March 31, 2016 was $116.4 million and was primarily driven by cash inflows as a result of a decrease of $89.7 million in inventories due to lower commodity prices and a

seasonal reduction in inventory requirements, a decrease of $25.4 million in derivative instruments relating to the ratable liquidation of our fixed forward contracts as we come out of the peak season and $29.8 million in net income. These inflows were offset by cash outflows as a result of a reduction of $27.5 million in accounts payable and accrued liabilities primarily relating to the timing of invoice payments for product purchases.

Table of Contents

Investing Activities

Net cash used in investing activities for the three months ended March 31, 2017 was $65.9 million of which $58.9 million related to the purchase of three acquisitions: a natural gas marketing business from Global Partners LP; an oil terminal and marketing business from L.E. Belcher, Incorporated; and an oil terminal from Capital Properties Inc. There were additional investing activities of $5.8 million related to expansion capital expenditures and $1.3 million related to maintenance capital expenditure projects across our terminal system.

Net cash used in investing activities for the three months ended March 31, 2016 was $32.6 million of which $29.1 million related to the purchase of the SBE natural gas business, $2.2 million related to expansion capital expenditures and $1.5 million related to maintenance capital expenditure projects across our terminal system.

Financing Activities

Net cash used in financing activities for the three months ended March 31, 2017 was $27.7 million and primarily resulted from $11.7 million of net payments under our Credit Agreement due to reduced financing requirements from lower commodity prices and accounts receivable levels and distributions of $13.8 million.

Net cash used in financing activities for the three months ended March 31, 2016 was $106.6 million and primarily resulted from $89.0 million of net payments under our Credit Agreement due to reduced financing requirements from lower commodity prices and accounts receivable levels and distributions of $11.4 million.

Impact of Inflation

Inflation in the United States and Canada has been relatively low in recent years and did not have a material impact on our results of operations for the three months ended March 31, 2017 and 2016.

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 consolidated financial statements are detailed in Note 1—“Description of Business and Summary of Significant Accounting Policies” included in our 2016 Annual Report. There have been no subsequent 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.

Table of Contents



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 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 ICE with the prices based on the Henry Hub location near Erath, Louisiana. The Henry Hub is the most active natural gas trading location in the United States. Although we typically use swaps, there is also an actively traded NYMEX Henry Hub natural gas futures contract that we can use. We primarily use ICE basis swaps as the key financial instrument type to hedge our natural gas basis risk. Similar to the natural gas futures and ICE Henry Hub swaps, basis swaps for major locations trade actively for many months. These swaps are financially settled, typically using prices quoted by Platts. We also directly hedge our price exposure in oil and natural gas by using forward purchases or sales that require physical delivery of the product.

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



	Three Months Ended March 31,
	2017		2016
Refined products contracts	$	33,567	$	33,033
Natural gas contracts	15,164		19,032
Total	$	48,731	$	52,065

Substantially all of our commodity derivative contracts outstanding as of March 31, 2017 will settle prior to September 30, 2018.

Table of Contents

Interest Rate Risk

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

Our interest rate swap agreements outstanding as of March 31, 2017 were as follows:



Interest Rate Swap Agreements
Beginning	Ending	Notional Amount
September 2016	April 2017	$	25,000
January 2017	January 2018	$	225,000
January 2018	January 2019	$	200,000

During the two year period ended March 31, 2017 we hedged approximately 42% of our floating rate debt with fixed-for-floating interest rate swaps. We expect to continue to utilize interest rate swaps to manage our exposure to LIBOR interest rates. Based on a sensitivity analysis for the twelve months ended March 31, 2017, we estimate that if short-term interest rates increased 100 basis points or decreased to zero, our interest expense would have increased by approximately $2.7 million and decreased by approximately $1.7 million, respectively. These amounts were estimated by considering the effect of the hypothetical short-term interest rates on variable-rate debt outstanding, adjusted for interest rate hedges.

Derivative Instruments

The following tables present all of our financial assets and financial liabilities measured at fair value on a recurring basis as of March 31, 2017:



	As of March 31, 2017
	Fair Value Measurement		Quoted Prices in Active Markets Level 1		Significant Other Observable Inputs Level 2		Significant Unobservable Inputs Level 3
Financial assets:
Commodity fixed forwards	$	61,884	$	—	$	61,884	$	—
Commodity swaps and options	621		—		621		—
Commodity derivatives	62,505		—		62,505		—
Interest rate swaps	1,518		—		1,518		—
Other	7		—		7		—
Total	$	64,030	$	—	$	64,030	$	—
Financial liabilities:
Commodity fixed forwards	$	46,846	$	—	$	46,846	$	—
Commodity swaps and options	212		—		212		—
Commodity derivatives	47,058		—		47,058		—
Interest rate swaps	193		—		193		—
Total	$	47,251	$	—	$	47,251	$	—

Table of Contents

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.

Table of Contents



Item 4.	Controls and Procedures

Disclosure Controls and Procedures

Our management, with the participation of our Chief Executive Officer and our Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures as of March 31, 2017. The term “disclosure controls and procedures,” as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended, or the Exchange Act, means controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits 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 by a company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the company’s management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Based on the evaluation of our disclosure controls and procedures as of March 31, 2017, our Chief Executive Officer and Chief Financial Officer concluded that, as of such date, our disclosure controls and procedures were effective at the reasonable assurance level.

Changes in Internal Control Over Financial Reporting

There have been no changes in our system of internal control over financial reporting during the three months ended March 31, 2017 that have materially affected, or are reasonably likely to materially affect, the Partnership’s internal control over financial reporting.

Table of Contents

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 “Risk Factors” included in our 2016 Annual Report, which could materially affect our business, financial condition or future results.



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

(a) On April 18, 2017, in connection with the closing of the acquisition of Carbo, pursuant to the terms of a unit purchase agreement, dated March 13, 2017, between Sprague Resources LP and Carbo Industries, Inc. (the “Unit Purchase Agreement”), we issued 1,131,551 common units to Carbo Industries, Inc. The common units were issued pursuant to the exemption set forth in Section 4(a)(2) of the Securities Act of 1933, as amended, and/or Rule 506 of Regulation D promulgated thereunder, based upon the investment representations made by Carbo Industries in the Unit Purchase Agreement, including its representation that it is an “accredited investor” within the meaning of Rule 501(a) of Regulation D and will be acquiring the common units for its own account and not with a view toward any distribution in violation of any securities laws.



Item 3.	Defaults Upon Senior Securities

None.



Item 4.	Mine Safety Disclosures

Not applicable.



Item 5.	Other Information

None.

Table of Contents



Item 6.	Exhibits

Exhibits are incorporated by reference or are filed with this report as indicated below (numbered in accordance with Item 601 of Regulation S-K).



Exhibit No.		Description


2.1***		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 24, 2017 (File No. 001-36137)).

2.2***		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)).

2.3***		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		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)).

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

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

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

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

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

101.INS*		XBRL Instance Document

101.SCH*		XBRL Taxonomy Extension Schema Document

101.CAL*		XBRL Taxonomy Extension Calculation

101.DEF*		XBRL Taxonomy Extension Definition

101.LAB*		XBRL Taxonomy Extension Label Linkbase

101.PRE*		XBRL Taxonomy Extension Presentation



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

Table of Contents

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.



	SPRAGUE RESOURCES LP

	By:	Sprague Resources GP LLC,
		Its General Partner

Date: May 8, 2017		/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)

Table of Contents

EXHIBIT INDEX

Exhibits are incorporated by reference or are filed with this report as indicated below.



Exhibit No.		Description

2.1***		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 24, 2017 (File No. 001-36137)).

2.2***		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)).

2.3***		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		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)).

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

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

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

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

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

101.INS*		XBRL Instance Document

101.SCH*		XBRL Taxonomy Extension Schema Document

101.CAL*		XBRL Taxonomy Extension Calculation

101.DEF*		XBRL Taxonomy Extension Definition

101.LAB*		XBRL Taxonomy Extension Label Linkbase

101.PRE*		XBRL Taxonomy Extension Presentation



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