Edgar Filing: Sprague Resources LP

Large accelerated filer

Accelerated filer

Non-accelerated filer

x (Do not check if a smaller reporting company)

Smaller reporting company

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2014

¨	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 ¨

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 ¨

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

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

The registrant had approximately 10,098,054 common units and approximately 10,071,970 subordinated units outstanding as of August 11, 2014

Table of Contents


		Page
PART I—FINANCIAL INFORMATION

Item 1.	Financial Statements:

	Consolidated Balance Sheets as of June 30, 2014 and December 31, 2013		3
	Unaudited Consolidated Statements of Operations for the three and six months ended June 30, 2014 and June 30, 2013		4
	Unaudited Consolidated Statements of Comprehensive (Loss) Income for the three and six months ended June 30, 2014 and June 30, 2013		5
	Unaudited Consolidated Statement of Unitholder’s Equity for the six months ended June 30, 2014		6
	Unaudited Consolidated Statements of Cash Flows for the six months ended June 30, 2014 and June 30, 2013		7
	Notes to Unaudited Consolidated Financial Statements		8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		22
Item 3.	Quantitative and Qualitative Disclosures about Market Risk		42
Item 4.	Controls and Procedures		45

PART II—OTHER INFORMATION

Item 1.	Legal Proceedings		46
Item 1A.	Risk Factors		46
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		46
Item 3.	Defaults Upon Senior Securities		46
Item 4.	Mine Safety Disclosures		46
Item 5.	Other Information		46
Item 6.	Exhibits		47
Signatures			48

Part I – FINANCIAL INFORMATION

Item 1 – Financial Statements

Sprague Resources LP

Consolidated Balance Sheets

(in thousands except unit amounts)


	June 30,			December 31,
	2014			2013
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	1,238		$	998
Accounts receivable, net		153,194			240,779
Inventories		148,079			348,107
Fair value of derivative assets		55,888			65,098
Deferred income taxes		1,541			2,207
Other current assets		18,939			25,369

Total current assets		378,879			682,558
Property, plant, and equipment, net		113,977			116,807
Intangibles and other assets, net		15,675			16,842
Goodwill		37,383			37,383

Total assets	$	545,914		$	853,590

Liabilities and unitholders’ equity
Current liabilities:
Accounts payable	$	67,241		$	175,187
Accrued liabilities		38,939			33,415
Fair value of derivative liabilities		76,165			130,954
Due to General Partner and affiliate		13,050			4,760
Current portion of long-term debt		—			126,652
Current portion of capital leases		206			193

Total current liabilities		195,601			471,161

Commitments and contingencies (Note 10)		—			—
Long-term debt		247,700			332,848
Long-term capital leases		2,962			3,067
Other liabilities		14,087			15,015
Due to General Partner		529			—
Deferred income taxes		1,674			1,540

Total liabilities		462,553			823,631

Unitholders’ equity:
Common unitholders—public (8,526,084 units and 8,506,666 units issued and outstanding, as of June 30, 2014 and December 31, 2013, respectively)		149,569			127,496
Common unitholders—affiliated (1,571,970 units issued and outstanding)		(8,772	)		(12,854	)
Subordinated unitholders—affiliated (10,071,970 units issued and outstanding)		(56,214	)		(82,356	)
Accumulated other comprehensive loss, net of tax		(1,222	)		(2,327	)

Total unitholders’ equity		83,361			29,959

Total liabilities and unitholders’ equity	$	545,914		$	853,590

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

Sprague Resources LP

Unaudited Consolidated Statements of Operations

(in thousands except units and per unit amounts)


	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
				Predecessor						Predecessor
Net sales	$	846,773		$	921,820		$	2,746,164		$	2,466,773
Cost of products sold		827,870			889,703			2,603,359			2,367,864

Gross margin		18,903			32,117			142,805			98,909
Operating costs and expenses:
Operating expenses		12,354			13,562			25,878			27,600
Selling, general and administrative		9,936			12,300			35,393			27,056
Depreciation and amortization		2,348			4,338			4,687			8,437

Total operating costs and expenses		24,638			30,200			65,958			63,093

Operating (loss) income		(5,735	)		1,917			76,847			35,816
Other income		—			973			—			816
Interest income		160			136			266			260
Interest expense		(4,194	)		(7,096	)		(9,689	)		(14,639	)

(Loss) income before income taxes		(9,769	)		(4,070	)		67,424			22,253
Income tax benefit (provision)		275			1,351			(1,583	)		(10,638	)

Net (loss) income	$	(9,494	)	$	(2,719	)	$	65,841		$	11,615

Net (loss) income per limited partner unit:
Common—basic	$	(0.47	)				$	3.27
Common—diluted	$	(0.47	)				$	3.27
Subordinated—basic and diluted	$	(0.47	)				$	3.27

Units used to compute net (loss) income per limited partner unit:
Common—basic		10,091,388						10,081,840
Common—diluted		10,091,388						10,084,821
Subordinated—basic and diluted		10,071,970						10,071,970

Distribution declared per common and subordinated units	$	0.4275					$	0.8400

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

Sprague Resources LP

Unaudited Consolidated Statements of Comprehensive (Loss) Income

(in thousands)


	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
				Predecessor						Predecessor
Net (loss) income	$	(9,494	)	$	(2,719	)	$	65,841		$	11,615
Other comprehensive income (loss), net of tax:
Unrealized gain (loss) on interest rate swaps
Net loss arising in the period		(36	)		(64	)		(99	)		(138	)
Reclassification adjustment related for losses realized in income		625			1,259			1,233			2,514

Net change in unrealized loss on interest rate swaps		589			1,195			1,134			2,376
Tax effect		(15	)		(481	)		(29	)		(956	)

		574			714			1,105			1,420
Foreign currency translation adjustment		—			(1,453	)		—			(2,665	)
Unrealized loss on inter-entity long-term foreign currency transactions		—			(2,175	)		—			(3,814	)

Other comprehensive income (loss)		574			(2,914	)		1,105			(5,059	)

Comprehensive (loss) income	$	(8,920	)	$	(5,633	)	$	66,946		$	6,556

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

Sprague Resources LP

Unaudited Consolidated Statements of Unitholders’ Equity

(in thousands)


										Accumulated
				Common-			Subordinated-			Other
	Common-			Sprague			Sprague			Comprehensive
	Public			Holdings			Holdings			(Loss) Income			Total
Balance at December 31, 2013	$	127,496		$	(12,854	)	$	(82,356	)	$	(2,327	)	$	29,959

Partnership net income		27,801			5,136			32,904			—			65,841
Other comprehensive income		—			—			—			1,105			1,105
Distribution to unitholders		(5,930	)		(1,092	)		(7,001	)		—			(14,023	)
Unit-based compensation		260			48			307			—			615
Repurchased units withheld for employee tax obligation		(58	)		(10	)		(68	)		—			(136	)

Balance at June 30, 2014	$	149,569		$	(8,772	)	$	(56,214	)	$	(1,222	)	$	83,361

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

Sprague Resources LP

Unaudited Consolidated Statements of Cash Flows

(in thousands)


	Six Months Ended
	June 30,
	2014			2013
				Predecessor
Cash flows from operating activities
Net income	$	65,841		$	11,615
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		6,054			10,137
Provision for doubtful accounts		607			900
(Gain) loss on sale of assets		(4	)		4
Gain on insurance recovery		—			(777	)
Deferred income taxes		770			(1,067	)
Non-cash unit-based compensation		615			—
Changes in assets and liabilities:
Accounts receivable		86,457			58,974
Inventories		200,028			133,046
Prepaid expenses and other assets		6,039			10,312
Fair value of commodity derivative instruments		(44,445	)		(24,768	)
Due to General Partner and affiliates		9,195			—
Accounts payable, accrued liabilities and other		(103,025	)		(80,028	)

Net cash provided by operating activities		228,132			118,348

Cash flows from investing activities
Purchases of property, plant and equipment		(1,665	)		(8,117	)
Proceeds from property insurance settlement		—			1,867
Proceeds from sale of assets		4			144

Net cash used in investing activities		(1,661	)		(6,106	)

Cash flows from financing activities
Net payments under credit agreements		(211,800	)		(101,881	)
Payments on capital lease liabilities and term debt		(92	)		(349	)
Payments on long-term terminal obligations		(326	)		(211	)
Advance from Parent		—			10,000
Dividend paid to Parent		—			(22,500	)
Distribution to unitholders		(14,023	)		—
Repurchased units withheld for employee tax obligation		(136	)		—
Net increase (decrease) in payable to Parent		146			(494	)

Net cash used in financing activities		(226,231	)		(115,435	)

Effect of exchange rate changes on cash balances held in foreign currencies		—			(64	)

Net change in cash and cash equivalents		240			(3,257	)
Cash and cash equivalents, beginning of period		998			3,691

Cash and cash equivalents, end of period	$	1,238		$	434

Supplemental disclosure of cash flow information
Cash paid for interest	$	8,644		$	12,899
Cash paid for taxes	$	988		$	2,623

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

Sprague Resources LP

Notes to Unaudited Consolidated Financial Statements

(in thousands unless otherwise stated)

1. Nature of Operations

Sprague Resources LP (the “Partnership”) is a Delaware limited partnership formed on June 23, 2011 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,” when used in a historical context prior to October 30, 2013, the completion date of the initial public offering of the Partnership’s common units (the “IPO”), refer to Sprague Operating Resources LLC, the “Predecessor” for accounting purposes and the successor to Sprague Energy Corp., also referenced as the “Predecessor” and when used in the present tense or prospectively, refer to Sprague Resources LP and its subsidiaries, including Sprague Operating Resources LLC (“OLLC”). Unless the context otherwise requires, references to “Axel Johnson” or the “Parent” 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.

Company Businesses

The Partnership is one of the largest independent wholesale distributors of refined products in the Northeast United States based on aggregate terminal capacity. The Partnership owns, operates, and/or controls a network of 16 refined products and materials handling terminals located in the Northeast United States. The Partnership also utilizes third-party terminals in the Northeast 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, residual fuel oil, kerosene, jet fuel and gasoline (primarily from refining companies, trading organizations and producers), and sells them to wholesale, commercial, and industrial customers. The natural gas segment purchases, sells and distributes natural gas to commercial and industrial customers in the Northeast and Mid-Atlantic. 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, coal, petroleum coke, caustic soda, tallow, pulp and heavy equipment. The Partnership’s other operations primarily includes the purchase and distribution of coal.

Since 2007 and through September 30, 2012, the Predecessor, through its wholly-owned foreign subsidiary, Sprague Energy Canada Ltd., owned a 50% equity investment in 9047-1137 Quebec Inc. (“Kildair”), whose primary business is the distribution of residual fuel oil and asphalt. Kildair was not part of the Partnership following the completion of the IPO and, accordingly, Kildair’s results of operations are not included in the results of the Partnership’s operations as discussed below.

In connection with the completion of the IPO, the Parent contributed to Sprague Holdings all of the ownership interests in the Predecessor. The Predecessor distributed to a wholly owned subsidiary of Sprague Holdings certain assets and liabilities, including among others, the equity investment in Kildair and accounts receivable and cash in an aggregate amount equal to the net proceeds of the IPO. Sprague Holdings then contributed all of the ownership interests in the Predecessor to the Partnership. All of the assets and liabilities of the Predecessor contributed to the Partnership by Sprague Holdings were recorded at the Parent’s historical cost, as the foregoing transactions are among entities under common control. See Note 2—Initial Public Offering. Kildair is not included in the Partnership’s consolidated financial statements effective October 30, 2013, the IPO date, at which time Kildair was distributed to an affiliate of the Parent.

Basis of Presentation

The consolidated financial statements included herein reflect all normal and recurring adjustments which, in the opinion of management, are necessary for a fair presentation of the Partnership’s consolidated financial position at June 30, 2014 and December 31, 2013 and the consolidated results of operations and cash flows for the three and six months ended June 30, 2014 and 2013, respectively. The unaudited results of operations for the interim periods reported are not necessarily indicative of results to be expected for the full year.

Sprague Resources LP

Notes to Unaudited Consolidated Financial Statements

(in thousands unless otherwise stated)

The consolidated financial statements include the accounts of the Partnership and its wholly-owned subsidiaries. Intercompany transactions between the Partnership, the Predecessor and its wholly-owned subsidiaries have been eliminated. Investments in affiliated companies, in which the Partnership or Predecessor own greater than 20% of the voting interest or investees where the Partnership or Predecessor exerts significant influence over such investee but lacks control over the investee are accounted for using the equity method.

The 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, 2013 as filed with the SEC on March 27, 2014 (the “2013 Annual Report”).

The significant accounting policies are described in Note 1 “Description of Business and Summary of Significant Accounting Policies” in the Partnership’s audited consolidated financial statement, included in the 2013 Annual Report, and are the same as are used in preparing these unaudited interim consolidated financial statements.

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.

Use of Estimates

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.

New Accounting Guidance

In May 2014, the Financial Accounting Standards Board issued Accounting Standard Update 2014-09, Revenue from Contracts with Customers, 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 Partnership is currently evaluating the potential impact of this guidance which is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. Early adoption is not permitted.

In April 2014, the Financial Accounting Standards Board issued Accounting Standard Update 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. This ASU revises the criteria for reporting discontinued operations and requires additional disclosures, both for discontinued operations and for individually significant dispositions and assets classified as held for sale not qualifying as discontinued operations. The Partnership has early adopted this guidance on a prospective basis. The adoption did not have a material impact on the Partnership’s consolidated interim financial statements.

2. Initial Public Offering

On October 30, 2013, in connection with the closing of the IPO, the Partnership sold to the public 8,500,000 of its common units, representing a 42% limited partner interest in the Partnership, at an initial public offering price of $18.00 per unit. Net proceeds of the sale of the common units were $140.3 million after deducting underwriting discounts and commissions, the structuring fee and offering expenses. As of June 30, 2014, the Parent, through its ownership of Sprague Holdings owns 1,571,970 common units and 10,071,970 subordinated units, representing an aggregate 58% limited partner interest in the Partnership. Sprague Holdings also owns the Partnership’s General Partner, which in turn owns a non-economic interest in the Partnership. The principal difference between the Partnership’s common units and subordinated units is that during the subordination period, the common units have the right to receive distributions of cash from distributable cash flow each quarter in an amount equal to $0.4125 per common unit, which is the amount defined in the partnership agreement as the minimum quarterly distribution, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of cash from distributable cash flow may be made on the subordinated units. Furthermore, no arrearages will accrue or be paid on the subordinated units. Upon expiration of the subordination period, any outstanding arrearages in payment of the minimum quarterly distribution on the common units will be extinguished (not paid), each outstanding subordinated unit will immediately convert into one common unit and will thereafter participate pro rata with the other common units in distributions.

Sprague Holdings currently holds incentive distribution rights (“IDR’s”) that entitle it to receive increasing percentages, up to a maximum of 50%, of the cash the Partnership distributes from distributable cash flow. Participation begins once distributions exceed $0.474375 per unit per quarter. The maximum distribution of 50% does not include any distributions that Sprague Holdings may receive on any limited partner units that it owns.

Sprague Resources LP

Notes to Unaudited Consolidated Financial Statements

(in thousands unless otherwise stated)

3. Acquisitions

Bridgeport Terminal

On July 31, 2013, the Predecessor purchased an oil terminal in Bridgeport, Connecticut for $20.7 million. This deep water facility includes 13 storage tanks with 1.3 million barrels of storage capacity for gasoline and distillate products with 11 storage tanks and 1.1 million barrels currently in service. The terminal will provide throughput services to third-parties for branded gasoline sales, and is expected to increase the Predecessor’s marketing of refined products, both gasoline and distillate, in the Connecticut market.

The acquisition was accounted for as a business combination and was financed with a capital contribution of $10.0 million from the Parent and $10.7 million of borrowings under the acquisition line of the Predecessor’s credit facility.

The following table summarizes the fair values of the assets acquired:


Property, plant and equipment	$	20,190
Intangible assets—customer relationships		510

Net assets acquired	$	20,700

The Predecessor recognized $0.2 million of acquisition related costs that were recorded as selling, general and administrative expense at the acquisition date.

Kildair

In October 2007, the Predecessor purchased a 50% equity interest in Kildair for $38.7 million. The share purchase agreement provided for the Predecessor to acquire the remaining 50% of Kildair in 2012, subject to terms and conditions within the discretion of the Predecessor, for an additional $27.5 million Canadian, plus a potential earn-out payment if EBITDA over the five year period exceeded $55.0 million Canadian.

On October 1, 2012 (the “acquisition date”), the Predecessor acquired control of Kildair by purchasing the remaining 50% equity interest. From October 1, 2012 and through the date of the IPO on October 30, 2013, the assets, liabilities, and results of operations of Kildair have been consolidated into the Predecessor’s financial statements. Kildair is not part of the Partnership’s net assets following the completion of the IPO.

The amount of net sales and net loss of Kildair included in the Predecessor’s Consolidated Statements of Operations for the three and six months ended June 30, 2013 are as follows:


	Three Months Ended			Six Months Ended
	June 30, 2013			June 30, 2013
Net sales	$	149,009		$	261,585
Net loss		(1,269	)		(4,121	)

4. Accumulated Other Comprehensive Loss, Net of Tax

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


	June 30,			December 31,
	2014			2013
Cumulative change in fair value of interest rate swaps, net of tax	$	(1,222	)	$	(2,327	)

Sprague Resources LP

Notes to Unaudited Consolidated Financial Statements

(in thousands unless otherwise stated)

5. Inventories


	June 30,		December 31,
	2014		2013
Petroleum and related products	$	146,493	$	344,403
Coal		982		1,886
Natural gas		604		1,818

Total inventories	$	148,079	$	348,107

Due to changing market conditions, the Partnership recorded a provision of $1.4 million and $1.0 million as of June 30, 2014 and December 31, 2013, respectively, to write-down petroleum and natural gas inventory to its net realizable value. These charges are included in cost of products sold in the Unaudited Consolidated Statements of Operations.

6. Debt


	June 30,		December 31,
	2014		2013
Credit agreement—current	$	—	$	126,652
Credit agreement—long term		247,700		332,848

Total debt	$	247,700	$	459,500

The Partnership’s revolving credit agreement (the “Credit Agreement”) was entered into on October 30, 2013 and has a maturity date of October 30, 2018. The Credit Agreement is secured by substantially all of the Partnership’s assets and includes a $750.0 million working capital facility used to fund working capital and post letters of credit and a $250.0 million acquisition facility. Borrowings under the Credit Agreement bear interest based on LIBOR, plus a specified margin, which is a function of the utilization of the Credit Agreement for the working capital facility and leverage ratio for the acquisition facility.

As of June 30, 2014 and December 31, 2013, working capital facility borrowings were $139.8 million and $351.6 million, respectively, and outstanding letters of credit were $27.7 million and $73.4 million, respectively. The working capital facility is subject to borrowing base reporting and as of June 30, 2014 and December 31, 2013, had a borrowing base of $332.0 million and $573.8 million, respectively. As of June 30, 2014, excess availability under the working capital facility was $164.5 million.

As of June 30, 2014 and December 31, 2013, acquisition line borrowings were $107.9 million for each respective period. As of June 30, 2014, excess availability under the acquisition facility was $142.1 million.

The weighted average interest rate at June 30, 2014 and December 31, 2013 was 2.9% for both periods. The current portion of amounts outstanding on the Credit Agreement at June 30, 2014 and December 31, 2013 represents the amounts intended to be repaid during the subsequent twelve month period, respectively.

The Credit Agreement contains certain restrictions and covenants, including among others, the requirement to maintain a minimum level of net working capital, a fixed charge coverage and a debt leverage ratio 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 June 30, 2014, the Partnership is in compliance with these financial covenants.

7. Related Party Transactions

The General Partner charges the Partnership for the reimbursements of costs of employees and related employee benefits and other overhead costs supporting the Partnership’s operations which amounted to $15.0 and $45.1 million for the three and six months ended June 30, 2014, respectively. Prior to the IPO, these expenses were incurred directly by the Predecessor. Through the General Partner, the Partnership also participates in certain of the Parent’s pension and other post-retirement benefits. Amounts due to the General Partner were $13.6 million and $4.8 million as of June 30, 2014 and December 31, 2013 respectively.

Sprague Resources LP

Notes to Unaudited Consolidated Financial Statements

(in thousands unless otherwise stated)

During the six months ended June 30, 2013, the Predecessor made a cash dividend to the Parent of $22.5 million as permitted by the Predecessor’s credit agreement and received an advance of $10.0 million from the Parent which was reclassified into equity as a capital contribution upon the successful completion of the acquisition of the oil terminal in Bridgeport, Connecticut.

During the six months ended June 30, 2013, the Parent charged the Predecessor $0.7 million for oversight and monitoring of the Predecessor. Such amounts are included in selling, general and administrative expenses in the Unaudited Consolidated Statement of Operations. Intercompany activities with the Parent are settled monthly and do not bear interest.

8. Segment Reporting

The Partnership is a wholesale and commercial distributor engaged in the purchase, storage, distribution and sale of refined products and natural gas, and also provides storage and handling services for a broad range of materials. The Partnership has four reporting operating segments that comprise the structure used by the chief operating decision makers (CEO and COO/CFO) to make key operating decisions and assess performance. These segments are refined products, natural gas, materials handling and other activities. Segment information includes Kildair since the acquisition date of October 1, 2012 through October 30, 2013, the date Kildair was contributed to an affiliate of Sprague Holdings in connection with the IPO.

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, gasoline and biofuels (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 from the Partnership. 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, hospitals and educational institutions.

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

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, 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 and commercial trucking activities unrelated to its refined products segment. Other activities are not reported separately as they represent less than 10% of consolidated net sales and adjusted gross margin.

The Partnership evaluates segment performance based on adjusted gross margin, which is gross margin 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), before allocations of corporate, terminal and trucking operating costs, depreciation, amortization, and interest. 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 periods presented below.

Sprague Resources LP

Notes to Unaudited Consolidated Financial Statements

(in thousands unless otherwise stated)

Summarized financial information for the Partnership’s reportable segments for the three and six months ended June 30, 2014 and 2013 is presented in the table below:


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2014			2013			2014			2013
				Predecessor						Predecessor
	(in thousands)						(in thousands)
Net sales:
Refined products	$	768,800		$	845,362		$	2,520,944		$	2,269,052
Natural gas		67,342			64,398			201,682			173,081
Materials handling		8,322			7,943			16,401			14,528
Other operations		2,309			4,117			7,137			10,112

Net sales	$	846,773		$	921,820		$	2,746,164		$	2,466,773

Adjusted gross margin(1):
Refined products	$	14,515		$	22,379		$	59,436		$	53,146
Natural gas		2,666			3,569			38,010			23,986
Materials handling		8,316			7,937			16,393			14,519
Other operations		321			996			568			2,369

Adjusted gross margin		25,818			34,881			114,407			94,020
Reconciliation to gross margin(2):
Deduct: total commodity derivative gains (losses) included in net income (loss)(3)		(8,985	)		15,712			(12,817	)		1,851
Add: realized commodity derivative (gains) losses included in net income (loss)(3)		2,070			(18,476	)		41,215			3,038

Gross margin		18,903			32,117			142,805			98,909

Operating costs and expenses not allocated to operating segments:
Operating expenses		12,354			13,562			25,878			27,600
Selling, general and administrative		9,936			12,300			35,393			27,056
Depreciation and amortization		2,348			4,338			4,687			8,437

Total operating costs and expenses		24,638			30,200			65,958			63,093

Operating (loss) income		(5,735	)		1,917			76,847			35,816
Other income		—			973			—			816
Interest income		160			136			266			260
Interest expense		(4,194	)		(7,096	)		(9,689	)		(14,639	)
Income tax benefit (provision)		275			1,351			(1,583	)		(10,638	)

Net (loss) income	$	(9,494	)	$	(2,719	)	$	65,841		$	11,615

(1)	Adjusted gross margin is a non-GAAP financial measure used by management and external users of the Partnership’s consolidated financial statements to assess the Partnership’s economic results of operations and its market value reporting to lenders.

(2)	Reconciliation of adjusted gross margin to gross margin, a comparable GAAP measure.

(3)	Both total commodity derivative gains and losses and realized commodity derivative gains and losses include amounts paid to enter into the settled contracts.

The Partnership had no single customer whose revenue was greater than 10% of total net sales for the three and six months ended June 30, 2014 and 2013, respectively. The Partnership’s foreign sales, primarily sales of refined products, asphalt and natural gas to its customers in Canada, were $1.1 million and $57.3 million for the three months ended June 30, 2014 and 2013, and $2.1 million and $127.5 million for the six months ended June 30, 2014 and 2013, respectively.

Segment Assets

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

As of June 30, 2014 and December 31, 2013, goodwill for the refined products, natural gas, and materials handling segments amounted to $28.2 million, $4.4 million, and $4.8 million, respectively.

Sprague Resources LP

Notes to Unaudited Consolidated Financial Statements

(in thousands unless otherwise stated)

9. Financial Instruments and Off-Balance Sheet Risk

Cash, Cash Equivalents, Accounts Receivable and Debt

As of June 30, 2014 and December 31, 2013, the carrying amounts of cash, cash equivalents and accounts receivable approximated fair value because of the short maturity of these instruments. As of June 30, 2014 and December 31, 2013, the carrying value of the Partnership’s debt approximated fair value due to the variable interest nature of these instruments.

Derivative Instruments

The following table presents all financial assets and financial liabilities of the Partnership measured at fair value on a recurring basis as of June 30, 2014 and December 31, 2013:


	As of June 30, 2014
			Quoted		Significant
			Prices in		Other		Significant
			Active		Observable		Unobservable
	Fair Value		Markets		Inputs		Inputs
	Measurement		Level 1		Level 2		Level 3
Financial assets:
Commodity exchange contracts	$	5	$	5	$	—	$	—
Commodity fixed forwards		55,818		—		55,818		—
Commodity swaps and options		65		—		65		—

Commodity derivatives		55,888		5		55,883		—
Interest rate swaps		—		—		—		—

Total	$	55,888	$	5	$	55,883	$	—

Financial liabilities:
Commodity exchange contracts	$	—	$	—	$	—	$	—
Commodity fixed forwards		74,842		—		74,842		—
Commodity swaps and options		69		—		69		—

Commodity derivatives		74,911		—		74,911		—
Interest rate swaps		1,254		—		1,254		—

Total	$	76,165	$	—	$	76,165	$	—


	As of December 31, 2013
			Quoted		Significant
			Prices in		Other		Significant
			Active		Observable		Unobservable
	Fair Value		Markets		Inputs		Inputs
	Measurement		Level 1		Level 2		Level 3
Financial assets:
Commodity exchange contracts	$	165	$	165	$	—	$	—
Commodity fixed forwards		64,729		—		64,729		—
Commodity swaps and options		204		—		204		—

Commodity derivatives		65,098		165		64,933		—
Interest rate swaps		—		—		—		—

Total	$	65,098	$	165	$	64,933	$	—

Sprague Resources LP

Notes to Unaudited Consolidated Financial Statements

(in thousands unless otherwise stated)


	As of December 31, 2013
			Quoted		Significant
			Prices in		Other		Significant
			Active		Observable		Unobservable
	Fair Value		Markets		Inputs		Inputs
	Measurement		Level 1		Level 2		Level 3
Financial liabilities:
Commodity fixed forwards	$	128,368	$	—	$	128,368	$	—
Commodity swaps and options		198		—		198		—

Commodity derivatives		128,566		—		128,566		—
Interest rate swaps		2,388		—		2,388		—

Total	$	130,954	$	—	$	130,954	$	—

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 Consolidated Balance Sheets. Information related to these offsetting arrangements as of June 30, 2014 and December 31, 2013 follows:


	As of June 30, 2014
									Gross Amount Not Offset in
	Gross								the Balance Sheet
	Amounts of			Gross		Amounts of
	Recognized			Amounts		Assets/						Cash
	Assets/			Offset in the		Liabilities in			Financial			Collateral
	Liabilities			Balance Sheet		Balance Sheet			Instruments			Posted			Net Amount
Commodity derivative assets	$	55,888		$	—	$	55,888		$	(6,227	)	$	(12	)	$	49,649


Commodity derivative liabilities	$	(74,911	)	$	—	$	(74,911	)	$	6,227		$	—		$	(68,684	)
Interest rate swap derivative liabilities		(1,254	)		—		(1,254	)		—			—			(1,254	)

Fair value of derivative liabilities	$	(76,165	)	$	—	$	(76,165	)	$	6,227		$	—		$	(69,938	)


	As of December 31, 2013
									Gross Amount Not Offset in
	Gross								the Balance Sheet
	Amounts of			Gross		Amounts of
	Recognized			Amounts		Assets/						Cash
	Assets/			Offset in the		Liabilities in			Financial			Collateral
	Liabilities			Balance Sheet		Balance Sheet			Instruments			Posted			Net Amount
Commodity derivative assets	$	65,098		$	—	$	65,098		$	(5,506	)	$	(4	)	$	59,588


Commodity derivative liabilities	$	(128,566	)	$	—	$	(128,566	)	$	5,506		$	—		$	(123,060	)
Interest rate swap derivative liabilities		(2,388	)		—		(2,388	)		—			—			(2,388	)

Fair value of derivative liabilities	$	(130,954	)	$	—	$	(130,954	)	$	5,506		$	—		$	(125,448	)

Sprague Resources LP

Notes to Unaudited Consolidated Financial Statements

(in thousands unless otherwise stated)

Commodity Derivatives

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. On a limited basis and within the Partnership’s risk management guidelines, the Partnership utilizes futures contracts, forward contracts, swaps, options and other derivatives to generate profits from changes in market prices. The Partnership invests in 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 investors to provide 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 the Consolidated Balance Sheets. 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 in the Consolidated Balance Sheets. Substantially all of the Partnership’s commodity derivative contracts outstanding as of June 30, 2014 will settle prior to December 31, 2015.

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 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) or other comprehensive income (loss) each period as appropriate. The Partnership’s fair value measurements are determined using the market approach and includes non-performance risk and time value of money considerations. Counterparty credit is considered for receivable balances, and the Partnership’s credit is considered for payable balances.

The Partnership determines fair value in accordance with Accounting Standards Codification (“ASC”) 820, “ Fair Value Measurements and Disclosures “ which established 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 that are derived indirectly from observable inputs or from quoted prices from markets that are less liquid. Measurements based on Level 2 inputs include over-the-counter 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 and interest rate swaps.

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

The Partnership does not offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) against the fair value of derivative instruments executed with the same counterparty under the same master netting arrangement. The Partnership had no right to reclaim, or obligation to return, cash collateral as of June 30, 2014 or December 31, 2013.

Sprague Resources LP

Notes to Unaudited Consolidated Financial Statements

(in thousands unless otherwise stated)

The following table presents total realized and unrealized (losses) gains on derivative instruments utilized for commodity risk management purposes for the three and six months ended June 30, 2014 and 2013. Such amounts are included in cost of products sold in the Unaudited Consolidated Statements of Operations:


	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
				Predecessor						Predecessor
Refined products contracts	$	136		$	18,603		$	9,997		$	12,063
Natural gas contracts		(9,121	)		(2,891	)		(22,814	)		(10,212	)

Total	$	(8,985	)	$	15,712		$	(12,817	)	$	1,851

Included in realized and unrealized (losses) gains on refined products derivatives instruments above are realized and unrealized losses on discretionary trading activities of $0.5 million and $1.2 million for the three and six months ended June 30, 2013, respectively. There were no discretionary trading activities for the three and six months ended June 30, 2014.

The following table presents the gross volume of commodity derivative instruments outstanding as of June 30, 2014 and December 31, 2013:


	As of June 30, 2014						As of December 31, 2013
	Refined Products			Natural Gas			Refined Products			Natural Gas
	(Barrels)			(MMBTUs)			(Barrels)			(MMBTUs)
				Predecessor						Predecessor
Long contracts		4,719			79,546			9,250			100,119
Short contracts		(5,471	)		(59,601	)		(11,538	)		(74,265	)

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. At June 30, 2014, the Partnership held three interest rate swap agreements with a notional value of $100.0 million that expire at various dates through January 2015.

There was no material ineffectiveness determined for the cash flow hedges for the three and six months ended June 30, 2014 and 2013, respectively. Any ineffectiveness is recorded as interest expense in the Unaudited Consolidated Statements of Operations.

The Partnership records unrealized gains and losses on its interest rate swaps as a component of accumulated other comprehensive income (loss), net of tax, which is reclassified to earnings as interest expense when the payments are made. As of June 30, 2014, the amount of unrealized losses, net of tax, expected to be reclassified to earnings during the following twelve-month period was $1.2 million.

Sprague Resources LP

Notes to Unaudited Consolidated Financial Statements

(in thousands unless otherwise stated)

The following table presents the location of the gains and losses on derivative contracts designated as cash flow hedging instruments reported in the Unaudited Consolidated Statements of Comprehensive Income as other comprehensive income (loss) (“OCL”) for the three and six months ended June 30, 2014 and 2013:

Three Months Ended June 30, 2014

Six Months Ended June 30, 2014

Amount of

Amount of Derivative

Amount of

Amount of Derivative

Derivative Loss

Loss Reclassified

Derivative Loss

Loss Reclassified

Recognized in

From Accumulated

Recognized in

From Accumulated

OCI

OCL Into Income

OCI

OCL Into Income

Interest rate swaps

625

1,233

Three Months Ended June 30, 2013

Six Months Ended June 30, 2013

Amount of

Amount of Derivative

Amount of

Amount of Derivative

Derivative Loss

Loss Reclassified

Derivative Loss

Loss Reclassified

Recognized in

From Accumulated

Recognized in

From Accumulated

OCL

OCL Into Income

OCL

OCL Into Income

Interest rate swaps

1,259

138

2,514

10. 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 ultimate 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. The Partnership maintains insurance coverage and deductibles that it believes are reasonable and prudent. However, the Partnership cannot assure that this insurance will be adequate to protect it from all material expenses related to potential future claims, or that these levels of insurance will be available in the future at economical prices.

11. Equity-Based Compensation

During the fiscal year ended December 31, 2013, the board of directors of the General Partner issued a total of 6,666 restricted unit awards to certain directors under the Sprague Resources 2013 Long-Term Incentive Plan (the “2013 LTIP”). Recipients have both voting rights and distribution rights on any unvested units. Distributions, if any, shall be paid to the holder of the restricted unit at the same time such distribution is paid to unitholders. The fair value of each restricted unit on the grant date is equal to the market price of the Partnership’s common unit on that date. The estimated fair value of the restricted units is amortized over the vesting period using the straight-line method. Total unrecognized compensation cost related to the nonvested restricted units totaled $0.1 million as of June 30, 2014, which is expected to be recognized over a period of approximately 28 months. The fair value of nonvested restricted units outstanding was approximately $0.2 million as of June 30, 2014.

On March 31, 2014, the board of directors of the General Partner granted 49,871 awards under the 2013 LTIP to certain directors and employees of the Partnership. Of these total awards, 26,186 (estimated grant date fair value of $0.5 million) were granted to directors and employees as vested common units. In connection with these vested awards, the Partnership reacquired from the recipients 6,768 units (estimated fair value of $0.1 million) to satisfy minimum tax withholding obligations. The remaining 23,685 awards (estimated grant date fair value of $0.5 million), consisted of phantom units issued to employees that are expected to vest as follows: 13,766 units on March 30, 2015 and 9,919 on March 30, 2016. Total unrecognized compensation related to phantom units was $0.4 million as of June 30, 2014 which is expected to be recognized on a straight-line basis over the vesting period. Recipients have distribution rights on any unvested phantom units, which distributions, if any, shall be paid to the holder of the phantom unit at the same time such distribution is paid to unitholders generally. The fair value of phantom units outstanding was approximately $0.6 million as of June 30, 2014.

Sprague Resources LP

Notes to Unaudited Consolidated Financial Statements

(in thousands unless otherwise stated)

A summary of the Partnership’s restricted unit award and phantom unit award activity for the six months ended June 30, 2014, is set forth below:


	Restricted Units				Phantom Units
			Weighted				Weighted
			Average Grant				Average Grant
			Date Fair Value				Date Fair Value
	Units		(per unit)		Units		(per unit)
Nonvested at December 31, 2013		6,666	$	17.33		—	$	—
Granted		—		—		23,685		20.16

Nonvested at June 30, 2014		6,666	$	17.33		23,685	$	20.16

Unit-based compensation expense for the three and six months ended June 30, 2014 was $0.1 million and $0.6 million, respectively, and is included in selling, general and administrative expenses.

12. Earnings Per Unit Calculation

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 (loss) is allocated to the limited partners in accordance with their respective partnership percentages, after giving effect to priority income allocations for incentive distributions, if any, to Sprague Holdings, the holder of the IDRs, pursuant to the partnership agreement, which are declared and paid following the close of each quarter. Earnings (losses) per unit is only calculated for the Partnership after the IPO as if no units were outstanding prior to October 30, 2013. 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 allocations used in the calculation of earnings per unit.

In addition to the common and subordinated units, the Partnership has also identified the IDRs and unvested restricted units as participating securities and uses the two-class method when calculating the net income (loss) per unit applicable to limited partners, which is based on the weighted-average number of common 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 restricted and phantom units. Basic and diluted earnings per unit applicable to common limited partners are the same in instances where including the effect of unvested restricted and phantom units would be anti-dilutive. Basic and diluted earnings (losses) per unit applicable to subordinated limited partners are the same because there are no potentially dilutive subordinated units outstanding.

Sprague Resources LP

Notes to Unaudited Consolidated Financial Statements

(in thousands unless otherwise stated)

The table below shows the weighted average common units outstanding used to compute net income per common unit for the three and six months ended June 30, 2014.


	Three Months Ended		Six Months Ended
	June 30, 2014		June 30, 2014
Weighted average limited partner common units—basic		10,091,388		10,081,840
Dilutive effect of unvested restricted and phantom units		—		2,981

Weighted average limited partner common units—diluted		10,091,388		10,084,821

The following table presents the allocation of net income to the partners for three and six months ended June 30, 2014:


	Three Months Ended June 30, 2014
	Common			Subordinated
	Units			Units			Total
	(in thousands, except for per unit amounts)
Net loss							$	(9,494	)

Distributions declared	$	4,317		$	4,306		$	8,623
Assumed net loss from operations after distributions		(9,069	)		(9,048	)		(18,117	)

Assumed net loss to be allocated	$	(4,752	)	$	(4,742	)	$	(9,494	)

Earnings per unit—basic	$	(0.47	)	$	(0.47	)
Earnings per unit—diluted	$	(0.47	)	$	(0.47	)

	Six Months Ended June 30, 2014
	Common			Subordinated
	Units			Units			Total
	(in thousands, except for per unit amounts)
Net income							$	65,841

Distributions declared	$	8,482		$	8,461		$	16,943
Assumed net income from operations after distributions		24,455			24,443			48,898

Assumed net income to be allocated	$	32,937		$	32,904		$	65,841

Earnings per unit—basic	$	3.27		$	3.27
Earnings per unit—diluted	$	3.27		$	3.27

13. 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.

On January 29, 2014, the Partnership declared a cash distribution totaling $5.7 million, or $0.2825 per unit with respect to the quarter ended December 31, 2013. Such cash distribution was calculated as the minimum quarterly cash distribution of $0.4125 per unit prorated for the period beginning October 30, 2013, the IPO closing date through December 31, 2013. Such distribution was paid on February 14, 2014 to unitholders of record on February 10, 2014.

On April 29, 2014, the Partnership declared a cash distribution totaling $8.3 million, or $0.4125 per unit for the three months ended March 31, 2014. Such distribution was paid on May 15, 2014, to unitholders of record on May 9, 2014.

Sprague Resources LP

Notes to Unaudited Consolidated Financial Statements

(in thousands unless otherwise stated)

14. Subsequent Events

Partnership Distribution

On July 29, 2014 the Partnership declared a cash distribution totaling $8.6 million, or $0.4275 per unit for the three months ended June 30, 2014. Such distribution will be paid on August 14, 2014, to unitholders of record on August 8, 2014.

Incentive Compensation Plans

In previous years the Partnership provided incentive compensation under a program that incorporated an annual bonus paid in cash for substantially all employees and a long term incentive program which was applicable to certain key executives that was also settled in cash. On July 11, 2014, the Board of Directors of the General Partner finalized and approved the 2014 Incentive Compensation Programs under the 2013 LTIP Plan. Under the 2014 programs, which include the annual discretionary bonus and the 2014 LTIP program, a portion of the annual discretionary bonus and all of the awards of the 2014 LTIP Program will be settled in common units. The Partnership estimates that approximately $3.6 million of the incentive compensation accrued as of June 30, 2014 will be settled in units based upon the provisions of these 2014 Programs.

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

Cautionary Statements Concerning Forward-Looking Statements

This Quarterly Report, on Form 10-Q for the quarter ended June 30, 2014 (the “Quarterly Report”), contains statements that we believe are “forward-looking statements”. Forward-looking statements give our current expectations and contain projections of results of operations or of financial condition, or forecasts of future events. Words such as “may”, “assume”, “forecast”, “position”, “predict”, “strategy”, “expect”, “intend”, “plan”, “estimate”, “anticipate”, “believe”, “project”, “budget”, “potential”, 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. Consequently, no forward-looking statements can be guaranteed. When considering these forward-looking statements, you should keep in mind the following risks and uncertainties:

•

We may not have sufficient distributable cash flow following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our General Partner and its affiliates, to enable us to pay the minimum quarterly distribution to our unitholders.

•

Our business could be affected by a range of issues, such as dramatic changes in commodity prices, energy conservation, competition, the global economic climate, movement of products between foreign locales and the United States, changes in local, domestic and worldwide inventory levels, seasonality and supply, weather and logistics disruptions.

•

A significant decrease in demand for the products and services we sell could reduce our ability to make distributions to our unitholders.

•

Increases and/or decreases in the prices of the products we sell could adversely impact the amount of borrowing available for working capital under our credit agreement.

•

Our results of operations are affected by the overall forward market for the products we sell.

•

Our business is seasonal and generally our financial results are lower in the second and third quarters of the calendar year, which may result in our need to borrow money in order to make quarterly distributions to our unitholders during these quarters. Warmer weather conditions could adversely affect our home heating oil, residual oil and natural gas sales.

•

Our risk management policies cannot eliminate all commodity risk. In addition, noncompliance with our risk management policies could result in significant financial losses.

•

Nonperformance by our customers, suppliers and counterparties could result in losses to us.

•

We are exposed to trade credit risk in the ordinary course of our business as well as risks associated with our trade credit support in the ordinary course of business.

•

Competition from alternative energy sources, energy efficiency and new technologies could result in loss of some of our customers or reduction in demand for our products and services.

•

Certain of our contracts must be renegotiated or replaced periodically and our results of operations may be affected if we are unable to renegotiate or replace such contracts.

•

Adverse developments in the geographic areas in which we operate could affect our results of operations.

•

Compliance with changes to both federal and state environmental and non-environmental regulations could have a material adverse effect on our businesses.

•

Any disruptions in our labor force could affect our business.

•

A serious disruption to our information technology systems could significantly limit our ability to manage and operate our business efficiently.

•

Any failure to develop or maintain adequate internal controls over financial reporting may affect our results of operations.

•

Our General Partner and its affiliates have conflicts of interest and limited fiduciary duties, which may permit them to favor their own interests to the detriment of unitholders.

•

Unitholders have limited voting rights and, even if they are dissatisfied, cannot initially remove our General Partner without its consent.

•

A significant increase in interest rates could adversely affect our ability to service our indebtedness.

•

The condition of credit markets may adversely affect us.

•

Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes. If the IRS were to treat us as a corporation for federal income tax purposes, our distributable cash flow would be substantially reduced.

•

Our unitholders will be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.

•

The other risks set forth in our Annual Report on Form 10-K for the year ended December 31, 2013.

The risk factors and other factors noted throughout this Quarterly Report could cause our actual results to differ materially from those contained in any forward-looking statement, and you are cautioned not to place undue reliance on any forward-looking statements.

Forward-looking statements 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 or review any forward-looking statements to reflect events or circumstances after the date of such statements.

As used in this Quarterly Report, unless the context otherwise requires, references to “Sprague Resources,” the “Partnership,” “we,” “our,” “us,” or like terms, when used in a historical context prior to October 30, 2013, the date on which the Partnership completed the initial public offering of its common units representing limited partner interests in the Sprague Resources LP (the “IPO”), refer to Sprague Operating Resources LLC, our “Predecessor” for accounting purposes and the successor to Sprague Energy Corp., also referenced as “our Predecessor” or “the Predecessor” and when used in the present tense or prospectively, refer to Sprague Resources LP and its subsidiaries. Unless the context otherwise requires, references to “Axel Johnson” or the “Parent” 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 our General Partner. References to our “General Partner” refer to Sprague Resources GP LLC.

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 and six months ended June 30, 2014 contained elsewhere in this Quarterly Report and the audited financial statements and related notes thereto as of and for the year ended December 31, 2013, included in our Annual Report on Form 10-K for the year ended December 31, 2013, as filed with the Securities Exchange Commission (the “SEC”) on March 27, 2014 (the “2013 Annual Report”).

A reference to a “Note” herein refers to the accompanying Notes to Consolidated Financial Statements contained in Part I, Item 1. “Financial Statements” of this Quarterly Report.

Please read Part II, Item 1A.“Risk Factors” for information regarding certain risks inherent in our business.

Overview

We are a Delaware limited partnership formed 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.

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 16 refined products and materials handling terminals strategically located throughout the Northeast that have a combined storage capacity of approximately 9.4 million barrels for refined products and other liquid materials, as well as approximately 1.5 million square feet of materials handling capacity. We also have an aggregate of approximately 2.3 million barrels of additional storage capacity attributable to 47 storage tanks not currently in service. This capacity is 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 60 third-party terminals in the Northeast 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. We evaluate the performance of our segments using adjusted gross margin, which is a non-GAAP financial measure used by management and external users of our consolidated financial statements to assess the economic results of operations. For a description of how we define adjusted gross margin, see Part I, Item 2 “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Adjusted Gross Margin and Adjusted EBITDA.”

On October 1, 2012, our Predecessor acquired control of Kildair, a Canadian distributor of residual fuel oil and asphalt and a commercial trucking business, by purchasing the remaining 50% equity interest. Prior to October 1, 2012, the results of operations of Kildair were recorded as equity in earnings of foreign affiliate. Since October 1, 2012 and through the date of our IPO on October 30, 2013, the assets, liabilities and results of operations of Kildair were consolidated into our financial statements, including our adjusted gross margin. We recorded Kildair’s residual fuel oil and asphalt business in our refined products segment and their commercial trucking business in our other operations segment. Kildair is not part of our net assets following the completion of the IPO.

Our refined products segment purchases a variety of refined products, such as heating oil, diesel fuel, residual fuel oil, kerosene, jet fuel, gasoline and biofuels (primarily from refining companies, trading organizations and producers), and sells them to our customers. We have wholesale customers who resell the refined products they purchase from us, and commercial customers who consume the refined products we sell them. 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, hospitals and educational institutions. For the three months ended June 30, 2014 and 2013, we sold approximately 254.5 million and 297.0 million gallons of refined products, respectively, and our refined products segment accounted for 56% and 64% of our adjusted gross margin, respectively. For the six months ended June 30, 2014 and 2013, we sold approximately 808.5 million and 765.0 million gallons of refined products, respectively, and our refined products segment accounted for 52% and 57% of our adjusted gross margin, respectively.

We also purchase, sell and distribute natural gas to more than 5,000 commercial and industrial customer accounts across 10 states in the Northeast and Mid-Atlantic. We purchase the natural gas we sell from natural gas producers and trading companies. For the three months ended June 30, 2014 and 2013, we sold 11.5 Bcf and 11.9 Bcf of natural gas respectively, and our natural gas segment accounted for 10% of our adjusted gross margin for both periods. For the six months ended June 30, 2014 and 2013, we sold 28.0 Bcf and 28.3 Bcf of natural gas, respectively and our natural gas segment accounted for 33% and 26% of our adjusted gross margin, respectively.

Our materials handling business 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, clay slurry, salt, gypsum, coal, petroleum coke, caustic soda, tallow, pulp and heavy equipment. For the three months ended June 30, 2014, we offloaded, stored and/or prepared for delivery 0.5 million short tons of products and 45.4 million gallons of liquid materials. For the three months ended June 30, 2013, we offloaded, stored and/or prepared for delivery 0.6 million short tons of products and 54.5 million gallons of liquid materials. For the three months ended June 30, 2014 and 2013, our materials handling segment accounted for 32% and 23% of our adjusted gross margin, respectively. For the six months ended June 30, 2014, we offloaded, stored and/or prepared for delivery 1.2 million short tons of products and 112.2 million gallons of liquid materials. For the six months ended June 30, 2013, we offloaded, stored and/or prepared for delivery 1.1 million short tons of products and 122.6 million gallons of liquid materials. For the six months ended June 30, 2014 and 2013, our materials handling segment accounted for 14% and 15% of our adjusted gross margin, respectively.

Our other operations segment includes the marketing and distribution of coal conducted in our Portland, Maine terminal. In 2013, our other operations also include certain commercial trucking activity performed by Kildair. For the three months ended June 30, 2014 and 2013, our other operations segment accounted for 2% and 3% of our adjusted gross margin, respectively. For the six months ended June 30, 2014 and 2013, our other operations segment accounted for 1% and 2% of our adjusted gross margin, respectively.

We take title to the products we sell in our refined products, natural gas and other operations segments. We do not take title to any of the products in our materials handling segment. 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.

Initial Public Offering

On October 30, 2013, in connection with the closing of the IPO, the Partnership sold to the public 8,500,000 of the Partnership’s common units, representing a 42% limited partner interest in the Partnership, at an initial public offering price of $18.00 per unit. Net proceeds of the sale of the common units were $140.3 million after deducting underwriting discounts and commissions, the structuring fee and offering expenses. As of June 30, 2014, Sprague Holdings owns 1,571,970 common units and 10,071,970 subordinated units, representing an aggregate 58% limited partner interest in the Partnership. Sprague Holdings also owns the Partnership’s General Partner, which in turn owns a non-economic interest in the Partnership.

The principal difference between the Partnership’s common units and subordinated units is that during the subordination period, the common units have the right to receive distributions of cash from distributable cash flow each quarter in an amount equal to $0.4125 per common unit, which is the amount defined in the partnership agreement as the minimum quarterly distribution, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of cash from distributable cash flow may be made on the subordinated units. Furthermore, no arrearages will accrue or be paid on the subordinated units. Upon expiration of the subordination period, any outstanding arrearages in payment of the minimum quarterly distribution on the common units will be extinguished (not paid), each outstanding subordinated unit will immediately convert into one common unit and will thereafter participate pro rata with the other common units in distributions.

Non-GAAP Financial Measures

We present the non-GAAP financial measures EBITDA, adjusted EBITDA and adjusted gross margin in this Quarterly Report. For a description of how we define EBITDA, adjusted EBITDA and adjusted gross margin, see Part I, Item 2. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — How Management Evaluates Our Results of Operations.” For a reconciliation of EBITDA, adjusted EBITDA and adjusted gross margin to the GAAP measures most directly comparable thereto, see “Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations”.

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) gross margin, (2) operating expenses, (3) selling, general and administrative (or SG&A) expenses, (4) heating degree days and (5) adjusted gross margin and adjusted EBITDA.

Gross Margin

We define gross margin as net sales minus costs of products sold. Net sales include sales of refined products and natural gas and the fees associated with the provision of materials handling services. Product costs include the cost of acquiring the refined products and natural gas that we sell and all associated costs to transport such products to the point of sale, as well as costs that we incur in providing materials handling services to our customers.

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. Commencing on October 30, 2013, 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

Our SG&A expenses include employee salaries and benefits, pension and 401(k) plan expenses, discretionary bonus, marketing costs, corporate overhead, professional fees, information technology and office space expenses. Commencing on October 30, 2013, employee wages, related employee expenses and certain rental costs included in our SG&A expenses are incurred on our behalf by our General Partner and reimbursed by us.

Heating Degree Days

A “degree day” is an industry measurement of temperature designed to evaluate energy demand and consumption. Degree days are based on how much the average temperature departs from a human comfort level of 65°F. Each degree of temperature above 65°F is counted as one cooling degree day, and each degree of temperature below 65°F is counted as one heating degree day. Degree days are accumulated each day over the course of a year and can be compared to a monthly or a long-term average, or 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 officially 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.

EBITDA

We define EBITDA as net income before interest, income taxes, depreciation and amortization. EBITDA is used as a supplemental financial measure by external users of our financial statements, such as investors, commercial banks, trade suppliers and research analysts, 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 cash sufficient to pay interest on our indebtedness and make distributions to our equity holders; and

•

The viability of acquisitions and capital expenditure projects.

EBITDA is not prepared in accordance with GAAP. EBITDA should not be considered an alternative to net income, operating income, cash flow from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. EBITDA excludes some, but not all, items that affect net income and operating income.

Adjusted Gross Margin and Adjusted EBITDA

Management utilizes adjusted gross margin and adjusted EBITDA to assist in reviewing our financial results and managing our business segments. We define adjusted gross margin as gross margin 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 and natural gas transportation contracts. We define adjusted EBITDA as EBITDA 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 and natural gas transportation contracts, adjusted for infrequent or non-recurring transactions such as gains on acquisition of business, the write-off of deferred offering costs and the net impact of bio-fuel excise tax credits. Management believes that adjusted gross margin and adjusted EBITDA provide information that reflects our market or economic performance. We trade, purchase and sell energy commodities with market values that are constantly changing, which makes it important for management to evaluate our performance, as well as our physical and derivative positions, on a daily basis. Management reviews the daily operational performance of our supply activities, as well as our monthly financial results, on an adjusted gross margin and adjusted EBITDA basis. Adjusted gross margin and adjusted EBITDA have no impact on reported volumes or net sales.

Adjusted gross margin and adjusted EBITDA are used as supplemental financial measures by management to describe our operations and economic performance to commercial banks, trade suppliers and other credit suppliers, to assess:

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The economic results of our operations;

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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 and adjusted EBITDA are not prepared in accordance with GAAP. Adjusted gross margin and adjusted EBITDA should not be considered as alternatives to net income, income from operations, cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP.

Hedging Activities

We economically hedge our inventory within the guidelines set in our risk management policy. 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 based in New York Harbor, or NYH, and also United States Gulf Cost, or USGC, with our inventory values determined after adjusting the NYH prices to the various inventory locations by adding expected cost differentials (primarily freight) compared to a NYH supply source. 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 monthly Inside FERC, or IFERC, assessments published by Platts near the beginning of the following month.

Similarly, we can economically 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 increase. If the market value of the transportation asset exceeds costs, we can 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). As 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 only show 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 more closely align 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.

Recent Trends and Outlook

This section identifies certain trends and outlook that may affect our financial performance and results of operations in the future. Our economic and industry-wide trends and outlook include the following:

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New, stricter environmental laws and regulations are increasing the compliance cost of terminal operations, which could adversely affect our results of operations and financial condition. Our operations are subject to federal, state and local laws and regulations regulating product quality specifications and other environmental matters. For example, recently the federal government has begun discussions about the merits of reinstating bio-fuel tax credits, and several states have either enacted, or are considering enacting, changes to the sulphur specifications for heating fuels. The trend in environmental regulation is towards more restrictions and limitations on activities that may affect the environment. We try to anticipate future regulatory requirements that might be imposed and to plan accordingly to remain in compliance with changing environmental laws and regulations and to minimize the costs of such compliance. However, there can be no assurances as to the timing and type of such changes in existing laws or the promulgation of new laws or the amount of any required expenditures associated therewith.

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Dodd-Frank regulations could increase costs associated with hedging our commodity exposure. We employ derivatives of the types subject to regulation as part of the Dodd–Frank Act. We, along with all participants in commodity markets, may face increased margin requirements on the derivatives we employ to hedge our commodity exposure, which would reduce capital available for other purposes.

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Consolidation of the Northeast terminal market. In recent years, major U.S. oil companies have disposed of various terminal assets in the Northeast and reduced their participation in wholesale marketing in the region. The key terminals remain in operation as an integral part of the supply chain, though they are generally controlled by other industry participants.

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Growth in exploration and production of shale gas has contributed to a relative weakness of domestic natural gas prices compared to competitive refined products in the Northeast, leading to expanded use of natural gas in our marketing area. Natural gas usage in the Northeast has grown substantially, as the supplies of gas from shale formations have grown both in the region (e.g. , Marcellus Shale) and the other parts of the United States. Further expansion of domestic natural gas supplies is expected, with consumption in the Northeast also expected to grow as infrastructure developments continue. Moreover, the growth in Marcellus Shale production continues to increase the availability of natural gas in our operating areas. This development is expected to decrease the need for traditional, long-distance sourcing of natural gas supplies using interstate pipeline capacity and natural gas storage capacity. In addition, the potential natural gas supply counterparties in our operating areas are expanding, and there are now some relatively short-term arrangements and additional hedging opportunities available in the Northeast, providing additional sources of liquidity to support our operations.

Factors that Impact our Business

Our results of operations and financial condition will depend in part upon certain economic or industry-wide factors, including the following:

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Seasonality and weather conditions. Our financial results are impacted by seasonality in our business and are generally better during the winter months, primarily because a material part of our business consists of supplying home heating oil, residual fuel oil and natural gas for space heating purposes during the winter. For example, historically, we generate approximately two-thirds of our total home heating oil and residual fuel oil net sales during the months of November through March.

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The impact of the market structure on our hedging strategy. We typically hedge our exposure to commodity price moves with NYMEX futures contracts and OTC swaps. In markets where futures prices are higher than spot prices (typically referred to as contango), we generate positive margins when rolling our inventory hedges to successive months. In markets where futures prices are lower than spot prices (typically referred to as backwardation), we realize losses when rolling our inventory hedges to successive months. In backwardated markets, we operate with lower inventory levels and, as a result, have reduced hedging and financing requirements, thereby limiting losses.

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Energy efficiency, new technology and alternative fuels could reduce demand for our products. Increased conservation and technological advances have adversely affected the demand for home heating oil and residual fuel oil. Consumption of residual fuel oil, in particular, has steadily declined in recent years, primarily due to customers converting from other fuels to natural gas, weak industrial demand and tightening of environmental regulations. Use of natural gas is expected to continue to displace other fuels, which we believe will favorably impact our natural gas volumes and margins.

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Absolute price increases can lead to reduced demand, increased credit risk, higher interest costs and temporarily reduced margins. Refined product prices have risen due to, among other things, investor interest in using commodities as an inflation hedge, U.S. dollar weakness and supply and demand fundamentals. For example, NYMEX heating oil (HO) contracts have risen from approximately $2.05 per gallon in June 2010 to approximately $2.96 per gallon in June 2014. As refined product prices rise, we generally experience reduced demand as customers engage in conservation efforts. We also experience a higher level of credit risk from our customers. In addition, our working capital requirements for holding inventory and financing receivables increase with higher price levels, while gross margin levels may stay relatively constant for a period of time due to competitive pressures.

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Interest rates could rise. Since mid-2009, the credit markets have been experiencing near-record lows in interest rates. As the overall economy strengthens, it is expected that monetary policy will tighten, resulting in higher interest rates to counter possible inflation. This could affect our ability to access the debt capital markets to the extent we may need to in the future to fund our growth. In addition, interest rates could be higher than current levels, causing our financing costs to increase accordingly. During the 24 months ended June 30, 2014, we hedged approximately 42% of our floating-rate debt with fixed-for-floating interest rate swaps. Although higher interest rates could limit our ability to raise funds in the debt capital markets, we expect to remain competitive with respect to acquisitions and capital projects, as our competitors would face similar circumstances. As with other yield-oriented securities, our unit price is impacted by the level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank related yield-oriented securities for investment decision-making purposes.

Comparability of our Financial Statements

Our future results of operations may not be comparable to our Predecessor’s historical results of operations for the reasons described below.

Our Predecessor’s historical results of operations include the results of operations of Kildair, an asphalt and residual fuel oil marketing, storage, and commercial trucking business that was owned by our Predecessor and was not contributed to us in connection with the IPO. Demand for Kildair’s asphalt business is generally higher during the period of April through September than during the period of November through March. The table below provides certain financial information relating to the operations of Kildair, since Kildair’s results of operations are included in the financial statements of our Predecessor, but are not part of our assets following the completion of the IPO.


	Three Months Ended		Six Months Ended
	June 30, 2013		June 30, 2013
	(unaudited)
	($ in thousands)
Net sales	$	149,009	$	261,585
Gross margin	$	6,875	$	9,334
Adjusted gross margin	$	6,875	$	9,334

Our results of operations can be impacted by swings in commodity prices, primarily in refined products and natural gas. 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 not recorded for GAAP financial reporting purposes because inventory is recorded at the lower of cost or market.

Our SG&A expenses have increased as a result of becoming a publicly traded partnership following the IPO. These expenses include increased accounting support services, increased costs associated with filing annual and quarterly reports with the SEC, audit fees, investor relations costs, directors’ fees, directors’ and officers’ insurance premiums, legal fees, stock exchange listing fees and registrar and transfer agent fees; however, such expenses are not fully reflected in our historical financial statements. Our financial statements following the completion of our IPO on October 30, 2013 reflect the impact of these increased expenses, which affects the comparability of our financial statements with periods prior to the completion of the IPO.

Results of Operations

The following tables present our volume, net sales, gross margin and adjusted gross margin by segment, as well our adjusted EBITDA and information on weather conditions, for the three and six months ended June 30, 2014 and 2013.


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2014			2013			2014			2013
				Predecessor						Predecessor
	(in thousands)						(in thousands)
Volumes:
Refined products (gallons)		254,520			296,984			808,458			765,032
Natural gas (MMBtus)		11,493			11,858			27,989			28,329
Materials handling (short tons)		525			623			1,219			1,078
Materials handling (gallons)		45,360			54,516			112,182			122,556
Other operations (short tons)		20			23			65			71
Net Sales:
Refined products	$	768,800		$	845,362		$	2,520,944		$	2,269,052
Natural gas		67,342			64,398			201,682			173,081
Materials handling		8,322			7,943			16,401			14,528
Other operations		2,309			4,117			7,137			10,112

Total net sales	$	846,773		$	921,820		$	2,746,164		$	2,466,773

Gross Margin:
Refined products	$	13,659		$	21,004		$	65,456		$	56,783
Natural gas		(3,393	)		2,180			60,388			25,238
Materials handling		8,316			7,937			16,393			14,519
Other operations		321			996			568			2,369

Total gross margin	$	18,903		$	32,117		$	142,805		$	98,909

Adjusted Gross Margin:
Refined products	$	14,515		$	22,379		$	59,436		$	53,146
Natural gas		2,666			3,569			38,010			23,986
Materials handling		8,316			7,937			16,393			14,519
Other operations		321			996			568			2,369

Total adjusted gross margin	$	25,818		$	34,881		$	114,407		$	94,020

Calculation of Adjusted Gross Margin:
Total gross margin	$	18,903		$	32,117		$	142,805		$	98,909
Deduct: total commodity derivative (gains) losses included in net income (loss)(1)		8,985			(15,712	)		12,817			(1,851	)
Add: realized commodity derivative gains (losses) included in net income (loss)(1)		(2,070	)		18,476			(41,215	)		(3,038	)

Total adjusted gross margin (2)	$	25,818		$	34,881		$	114,407		$	94,020


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2014			2013			2014			2013
				Predecessor						Predecessor
	(in thousands)						(in thousands)
Reconciliation to Net Income:
Gross margin	$	18,903		$	32,117		$	142,805		$	98,909
Operating costs and expenses not allocated to operating segments:
Operating expenses		12,354			13,562			25,878			27,600
Selling, general and administrative		9,936			12,300			35,393			27,056
Depreciation and amortization		2,348			4,338			4,687			8,437

Total operating costs and expenses		24,638			30,200			65,958			63,093

Operating income		(5,735	)		1,917			76,847			35,816
Other (expense) income		—			973			—			816
Interest income		160			136			266			260
Interest expense		(4,194	)		(7,096	)		(9,689	)		(14,639	)
Income tax provision		275			1,351			(1,583	)		(10,638	)

Net income	$	(9,494	)	$	(2,719	)	$	65,841		$	11,615

Reconciliation of EBITDA to Net Income:
Net income	$	(9,494	)	$	(2,719	)	$	65,841		$	11,615
Add/(deduct):
Interest expense, net		4,034			6,960			9,423			14,379
Tax (benefit) expense		(275	)		(1,351	)		1,583			10,638
Depreciation and amortization		2,348			4,338			4,687			8,437

EBITDA (2):	$	(3,387	)	$	7,228		$	81,534		$	45,069

Deduct: total commodity derivative (gains) losses included in net income (loss)(1)		8,985			(15,712	)		12,817			(1,851	)
Add: realized commodity derivative gains (losses) included in net income (loss)(1)		(2,070	)		18,476			(41,215	)		(3,038	)
Add/(deduct): Bio-fuel excise tax credits (3)		—			—			—			(5,021	)

Adjusted EBITDA (2):	$	3,528		$	9,992		$	53,136		$	35,159

Other Data:
Normal heating degree days(4)		954			954			4,228			4,228
Actual heating degree days		935			929			4,541			4,077
Variance from normal heating degree days		(2	)%		(2.6	)%		7.4	%		(3.6	)%
Variance from prior period actual heating degree days		0.6	%		15.1	%		11.4	%		15.3	%

(1)	Both total commodity derivative gains and losses and realized commodity derivative gains and losses include amounts paid to enter into settled contracts.

(2)	For a discussion of the non-GAAP financial measures EBITDA, adjusted EBITDA and adjusted gross margin, see “Part I, Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations – How Management Evaluates Our Results of Operations.”

(3)

On January 2, 2013, the federal government enacted legislation that reinstated an excise tax credit program available for certain of our bio-fuel blending activities. This program had previously expired on December 31, 2011 and was reinstated retroactively to January 1, 2012. During the three months ended March 31, 2013, we recorded federal excise tax credits of $5.0 million related to our bio-fuel blending activities that had occurred during the year ended December 31, 2012. These credits have been recorded as a reduction of cost of products sold and, therefore, resulted in an increase in adjusted gross margin for the six months ended June 30, 2013. This adjustment reflects the effect on our adjusted EBITDA had these credits been recorded in the period in which the blending activity took place.

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

Three Months Ended June 30, 2014 compared to Three Months Ended June 30, 2013

Our results of operations for the three months ended June 30, 2014 reflect decreasing sales volumes, net sales and unit gross margin in our refined products segment; increasing net sales and decreasing sales volumes and unit gross margin in our natural gas segment; and increasing net sales and gross margin in our materials handling segment.

Adjusted gross margin for the three months ended June 30, 2014 reflects decreasing adjusted unit gross margin for refined products and decreasing adjusted unit gross margin for natural gas.


	Three Months Ended
	June 30,					Increase/(Decrease)
	2014			2013		$			%
				Predecessor
	($ in thousands, except unit gross margin and
	adjusted unit gross margin)
Volumes:
Refined products (gallons)		254,520			296,984		(42,464	)		(14	)%
Natural gas (MMBtus)		11,493			11,858		(365	)		(3	)%
Materials handling (short tons)		525			623		(98	)		(16	)%
Materials handling (gallons)		45,360			54,516		(9,156	)		(17	)%
Other operations (short tons)		20			23		(3	)		(13	)%
Net Sales:
Refined products	$	768,800		$	845,362	$	(76,562	)		(9	)%
Natural gas		67,342			64,398		2,944			5	%
Materials handling		8,322			7,943		379			5	%
Other operations		2,309			4,117		(1,808	)		(44	)%

Total net sales	$	846,773		$	921,820	$	(75,047	)		(8	)%

Gross Margin:
Refined products	$	13,659		$	21,004	$	(7,345	)		(35	)%
Natural gas		(3,393	)		2,180		(5,573	)		(256	)%
Materials handling		8,316			7,937		379			5	%
Other operations		321			996		(675	)		(68	)%

Total gross margin	$	18,903		$	32,117	$	(13,214	)		(41	)%

Unit Gross Margin:
Refined products	$	0.054		$	0.071	$	(0.017	)		(24	)%
Natural gas	$	(0.295	)	$	0.184	$	(0.479	)		(260	)%
Adjusted Gross Margin:
Refined products	$	14,515		$	22,379	$	(7,864	)		(35	)%
Natural gas		2,666			3,569		(903	)		(25	)%
Materials handling		8,316			7,937		379			5	%
Other operations		321			996		(675	)		(68	)%

Total adjusted gross margin	$	25,818		$	34,881	$	(9,063	)		(26	)%

Adjusted Unit Gross Margin:
Refined products	$	0.057		$	0.075	$	(0.018	)		(24	)%
Natural gas	$	0.232		$	0.301	$	(0.069	)		(23	)%

Refined Products

Refined products net sales were $768.8 million and $845.4 million for the three months ended June 30, 2014 and 2013, respectively. Excluding Kildair’s net sales of $146.4 million for the three months ended June 30, 2013, the refined products net sales increased $69.8 million, or 10%, which was driven primarily by higher sales volumes. Excluding Kildair’s sales volumes of 57.1 million gallons for the three months ended June 30, 2013, refined products sales volumes were 254.5 million gallons and 239.9 million gallons for the three months ended June 30, 2014 and 2013, respectively. Distillate sales volumes increased 16.1 million gallons, or 10%, period over period, with a significant increase in diesel sales more than offsetting a reduction in heating oil volumes. The increase in diesel volumes was driven by contracts acquired from Hess Corporation at the end of 2013. A key factor leading to the lower heating oil volumes was a reduction in high sulfur heating oil inventories during the quarter in preparation for the July 1, 2014 transition to the low sulfur (500 ppm) heating oil specification in many of the states (MA, VT, RI, CT and NJ) where we operate.

Gasoline sales volumes decreased by approximately 2.2 million gallons, or 4%, for the three months ended June 30, 2014 as compared to the same period in 2013. Residual fuel oil sales volumes increased 0.8 million gallons, or 5%, for the three months ended June 30, 2014 as compared to the same period in 2013, The average refined products selling price per gallon was slightly higher for the three months ended June 30, 2014 as compared to the same period in 2013.

Excluding Kildair’s gross margin and adjusted gross margin of $6.2 million for the three months ended June 30, 2013, refined products gross margin was $13.7 million and $14.8 million for the three months ended June 30, 2014 and 2013, respectively. Refined products adjusted gross margin, exclusive of Kildair, was $14.5 million and $16.2 million for the three months ended June 30, 2014 and 2013, respectively. For the three months ended June 30, 2014 and 2013, refined products adjusted gross margin was $0.8 million and $1.4 million higher, respectively, than gross margin due to changes in the difference between total commodity derivative gains and losses and realized commodity derivative gains and losses.

Excluding Kildair, the refined products adjusted gross margin decrease of $1.7 million, or 10%, was primarily attributable to a decline in heating oil contribution. Volumes and unit margins for home heating oil were lower due to a combination of competitive pressures and the changeover from high sulphur to lower sulphur heating oil in certain of our markets which impacted product availability and margins. Offsetting this result, diesel fuel margins were higher primarily as a result of sales to former Hess Corporation customers. Gasoline volumes and margins were down slightly from the previous year. Residual fuel oil volumes were slightly higher but margin was lower as a result of a less attractive market structure to hedge heavy oil inventory.

Natural Gas

Natural gas net sales were $67.3 million and $64.4 million for the three months ended June 30, 2014 and 2013, respectively. The natural gas sales increase of $2.9 million, or 5%, was driven by higher commodity prices as the average natural gas price per MMBtu was approximately 8% higher during the three months ended June 30, 2014 as compared to the same period in 2013. Natural gas sales volumes decreased approximately 3% for the three months ended June 30, 2014 as compared to the same period in 2013.

Natural gas gross margin was $(3.4) million and $2.2 million for the three months ended June 30, 2014 and 2013, respectively. Natural gas adjusted gross margin was $2.7 million and $3.6 million for the three months ended June 30, 2014 and 2013, respectively. Natural gas adjusted gross margin was $6.1 million higher than natural gas gross margin for the three months ended June 30, 2014 and $1.4 million higher than natural gas gross margin for the three months ended June 30, 2013 due to changes in the difference between natural gas total commodity derivative gains and losses and natural gas realized commodity derivative gains and losses.

The natural gas adjusted gross margin decrease of $0.9 million, or 25%, was primarily due to a combination of reduced margin generation opportunities from optimization of transportation assets and storage utilization and to a lesser extent reduced demand.

Materials Handling

Materials handling net sales were $8.3 million and $7.9 million for the three months ended June 30, 2014 and 2013, respectively. The materials handling net sales increase of $0.4 million, or 5%, was primarily due to the recovery of additional heating fees from customers as a result of higher fuel costs. This additional revenue was essentially offset by the higher heating operating costs measured during the period.

The materials handling gross margin increase of $0.4 million, or 5%, was primarily due to an increase in the higher heating charges discussed above. For the three months ended June 30, 2014, margins were higher due to windmill component handling activity with this gain offset by decreases in dry and liquid bulk. The bulk margins were down largely due to differences in the timing of deliveries for gypsum, furnace slag and china clay, which was substantially offset by increased salt volumes following the modest salt handling requirements in the three months ended March 31, 2013.

Other Operations

Net sales from our other operations were $2.3 million and $4.1 million for the three months ended June 30, 2014 and 2013, respectively, representing a decrease of $1.8 million. Excluding net sales of $2.7 million from Kildair’s commercial trucking activities for the three months ended June 30, 2013, other operations revenue increased $0.9 million.

Gross margins from our other operations were $0.3 million and $1.0 million for the three months ended June 30, 2014 and 2013, respectively, representing a decrease of $0.7 million. Excluding gross margin of $0.7 million from Kildair’s commercial trucking activities for the three months ended June 30, 2013, gross margin remained unchanged.

Six Months Ended June 30, 2014 compared to Six Months Ended June 30, 2013

Our results of operations for the six months ended June 30, 2014 reflect increasing sales volumes, net sales and unit gross margin in our refined products segment; decreasing sales volumes and increasing net sales and unit gross margin in our natural gas segment; and increasing net sales and gross margin in our materials handling segment.

Adjusted gross margin for the six months ended June 30, 2014 reflects increasing adjusted unit gross margin for refined products and increasing adjusted unit gross margin for natural gas.


	Six Months Ended
	June 30,				Increase/(Decrease)
	2014		2013		$			%
			Predecessor
	($ in thousands, except unit gross margin and
	adjusted unit gross margin)
Volumes:
Refined products (gallons)		808,458		765,032		43,426			6	%
Natural gas (MMBtus)		27,989		28,329		(340	)		(1	)%
Materials handling (short tons)		1,219		1,078		141			13	%
Materials handling (gallons)		112,182		122,556		(10,374	)		(8	)%
Other operations (short tons)		65		71		(6	)		(8	)%
Net Sales:
Refined products	$	2,520,944	$	2,269,052	$	251,892			11	%
Natural gas		201,682		173,081		28,601			17	%
Materials handling		16,401		14,528		1,873			13	%
Other operations		7,137		10,112		(2,975	)		(29	)%

Total net sales	$	2,746,164	$	2,466,773	$	279,391			11	%

Gross Margin:
Refined products	$	65,456	$	56,783	$	8,673			15	%
Natural gas		60,388		25,238		35,150			139	%
Materials handling		16,393		14,519		1,874			13	%
Other operations		568		2,369		(1,801	)		(76	)%

Total gross margin	$	142,805	$	98,909	$	43,896			44	%

Unit Gross Margin:
Refined products	$	0.081	$	0.074	$	0.007			9	%
Natural gas	$	2.158	$	0.891	$	1.267			142	%
Adjusted Gross Margin:
Refined products	$	59,436	$	53,146	$	6,290			12	%
Natural gas		38,010		23,986		14,024			58	%
Materials handling		16,393		14,519		1,874			13	%
Other operations		568		2,369		(1,801	)		(76	)%

Total adjusted gross margin	$	114,407	$	94,020	$	20,387			22	%

Adjusted Unit Gross Margin:
Refined products	$	0.074	$	0.069	$	0.005			7	%
Natural gas	$	1.358	$	0.847	$	0.511			60	%

Refined Products

Refined products net sales were $2.5 billion and $2.3 billion for the six months ended June 30, 2014 and 2013, respectively. Excluding Kildair’s net sales of $256.3 million for the six months ended June 30, 2013, the refined products net sales increased $508.2 million, or 25%, which was driven primarily by higher sales volumes. Excluding Kildair’s sales volumes of 109.6 million gallons for the six months ended June 30, 2013, refined products sales volumes were 808.5 million gallons and 655.4 million gallons for the six months ended June 30, 2014 and 2013, respectively. Distillate sales volumes increased 144.3 million gallons, or 28%, period over period, with substantial increases in both diesel and heating oil. The largest volume increases were in diesel fuel due to the contracts acquired from Hess Corporation at the end of 2013 and enhanced sales for power generation requirements as the colder weather conditions in the winter led to natural gas curtailments. Heating oil volumes were also up sharply, driven by sustained colder weather conditions during the winter and increased share in key markets due to both enhanced asset positions, including the Bridgeport, CT terminal that was purchased in the second half of 2013.

Gasoline sales volumes decreased by approximately 11.4 million gallons, or 11%, for the six months ended June 30, 2014 as compared to the same period in 2013. This decrease was primarily a result of aggressive pricing by our competitors in our key markets. Residual fuel oil sales volumes increased 20.2 million gallons, or 56%, for the six months ended June 30, 2014 as compared to the same period in 2013, with the volume gains largely occurring in the winter months due to natural gas curtailments primarily due to the colder weather. The average refined products selling price per gallon was flat for the six months ended June 30, 2014 as compared to the same period in 2013.

Excluding Kildair’s gross margin and adjusted gross margin of $7.9 million for the six months ended June 30, 2013, refined products gross margin was $65.5 million and $48.9 million for the six months ended June 30, 2014 and 2013, respectively. Refined products adjusted gross margin, exclusive of Kildair, was $59.4 million and $45.2 million for the six months ended June 30, 2014 and 2013, respectively. For the six months ended June 30, 2014 and 2013, refined products adjusted gross margin was $6.1 million and $3.7 million lower, respectively, than refined products gross margin due to changes in the difference between refined products total commodity derivative gains and losses and refined products realized commodity derivative gains and losses.

Excluding Kildair, the key factor leading to the gain in refined products adjusted gross margin increase of $14.2 million, or 31%, was improved returns in distillate fuels. The most significant gain for distillates was in heating oil, due to higher volumes, with improved unit margins also a significant contributor. Diesel volumes and adjusted unit margins also increased, with the volume gains being the most significant factor leading to the improved margin generation. The diesel volume increase was largely a result of the gains from sales to the former Hess Corporation customers as well as the incremental power generation requirements resulting from natural gas curtailments. Gasoline volumes and margins were down slightly from the previous year. Higher residual fuel sales volumes were partially offset by a less attractive market structure to hedge heavy fuel oil inventory.

In January 2013 a previously expired bio-fuel excise tax credit was retroactively reinstated to include all applicable 2012 activity. As a result, the refined products adjusted gross margin results for the six months ended June 30, 2013 include a $5.0 million credit. There was no comparable adjustment for the six months ended June 30, 2014.

Natural Gas

Natural gas net sales were $201.7 million and $173.1 million for the six months ended June 30, 2014 and 2013, respectively. The natural gas sales increase of $28.6 million, or 17%, was driven by higher commodity prices as the average natural gas marketing price per MMBtu was approximately 18% higher during the six months ended June 30, 2014 as compared to the same period in 2013. The stronger natural gas price environment was due in part to the higher demand driven by colder weather during the first six months of 2014, in particular during the first quarter. Natural gas sales volumes were flat for the six months ended June 30, 2014 as compared to the same period in 2013.

Natural gas gross margin was $60.4 million and $25.2 million for the six months ended June 30, 2014 and 2013, respectively. Natural gas adjusted gross margin was $38.0 million and $24.0 million for the six months ended June 30, 2014 and 2013, respectively. Natural gas adjusted gross margin was $22.4 million lower than natural gas gross margin for the six months ended June 30, 2014 and $1.2 million lower than natural gas gross margin for the six months ended June 30, 2013 due to changes in the difference between natural gas total commodity derivative gains and losses and natural gas realized commodity derivative gains and losses.

The natural gas adjusted gross margin increase of $14.0 million, or 58%, was primarily due to higher demand supported by the colder weather conditions during the winter, the continuing transition of our customer base towards smaller commercial and industrial end users with higher unit margins, and additional margin generation from optimization of transportation assets and storage utilization, particularly during volatile pricing periods.

Materials Handling

Materials handling net sales were $16.4 million and $14.5 million for the six months ended June 30, 2014 and 2013, respectively. The materials handling net sales increase of $1.9 million, or 13%, was primarily due to higher dry bulk handling volumes. These gains were partially offset by decreased asphalt handling revenue.

The materials handling gross margin increase of $1.9 million, or 13%, was primarily due to an increase in dry bulk handling volumes of salt and petroleum coke, with a modest decline in gypsum. This gain was driven by a combination of low activity in 2013 due to high bulk product inventories as a result of warm weather (e.g. salt) and timing differences in deliveries. The dry bulk product gains were partially offset by a reduction in asphalt margin due to delivery timing differences (i.e. a shipment in late 2013 rather than early 2014) and a temporarily out-of-service tank.

Other Operations

Net sales from our other operations were $7.1 million and $10.1 million for the six months ended June 30, 2014 and 2013, respectively, representing a decrease of $3.0 million. Excluding net sales of $5.3 million from Kildair’s commercial trucking activities for the six months ended June 30, 2013, other revenue increased $2.3 million.

Gross margins from our other operations were $0.6 million and $2.4 million for the three months ended June 30, 2014 and 2013, respectively, representing a decrease of $1.8 million. Excluding gross margin of $1.4 million from Kildair’s commercial trucking activities for the six months ended June 30, 2013, gross margin decreased $0.4 million.

Operating Costs and Expenses

Three Months Ended June 30, 2014 compared to Three Months Ended June 30, 2013


	Three Months Ended June 30,				Increase/(Decrease)
	2014		2013		$			%
			($ in thousands)
Operating expenses	$	12,354	$	13,562	$	(1,208	)		(9	)%
Selling, general and administrative expenses	$	9,936	$	12,300	$	(2,364	)		(19	)%
Depreciation and amortization	$	2,348	$	4,338	$	(1,990	)		(46	)%

Operating Expenses. Operating expenses for the three months ended June 30, 2014 decreased $1.2 million, or 9%, as compared to the three months ended June 30, 2013. Excluding Kildair’s operating expenses for the three months ended June 30, 2013 of $2.7 million, operating expenses increased $1.4 million or 13%. Of this increase $0.9 million was due to terminal operating expenses related to our Bridgeport terminal which was acquired on July 31, 2013, and $0.5 million was primarily due to increased maintenance and utility expenses.

Selling, General and Administrative Expenses. Selling, general and administrative expenses for the three months ended June 30, 2014, decreased $2.4 million, or 19%, as compared to the three months ended June 30, 2013. Excluding Kildair’s expenses for the three months ended June 30, 2013 of $1.4 million, selling, general and administrative expenses decreased by $1.0 million or 9%. Of this decrease $1.4 million was due to lower employee related expenses which were primarily attributed to decreased discretionary incentive compensation and lower sales commissions from lower earnings performance. This decrease was partially offset by $0.4 million in increased professional fees associated with public company reporting and compliance requirements.

Depreciation and Amortization. Depreciation and amortization for the three months ended June 30, 2014 decreased $2.0 million, or 46% as compared to the three months ended June 30, 2013. Of this decrease $2.0 million was due to Kildair’s depreciation expense in the three months ended June 30, 2013.

Six Months Ended June 30, 2014 compared to Six Months Ended June 30, 2013


	Six Months Ended June 30,				Increase/(Decrease)
	2014		2013		$			%
			($ in thousands)
Operating expenses	$	25,878	$	27,600	$	(1,722	)		(6	)%
Selling, general and administrative expenses	$	35,393	$	27,056	$	8,337			31	%
Depreciation and amortization	$	4,687	$	8,437	$	(3,750	)		(44	)%

Operating Expenses. Operating expenses for the six months ended June 30, 2014 decreased $1.7 million, or 6%, as compared to the six months ended June 30, 2013. Excluding Kildair’s operating expenses for the six months ended June 30, 2013 of $5.6 million, operating expenses increased $3.9 million or 18%. Of this increase, $0.7 million was due to increased dry bulk handling volumes, $1.7 million was due to terminal operating expenses related to our Bridgeport terminal which was acquired on July 31, 2013, and $1.5 million was primarily due to increased employee, utility and maintenance expenses.

Selling, General and Administrative Expenses. Selling, general and administrative expenses for the six months ended June 30, 2014, increased $8.3 million, or 31%, as compared to the six months ended June 30, 2013. Excluding Kildair’s expenses for the six months ended June 30, 2013 of $2.6 million, selling, general and administrative expenses increased by $10.9 million or 44%. Of this increase $8.8 million was due to higher employee related expenses primarily attributed to increased discretionary incentive compensation and sales commissions as a result of higher earnings performance, $1.7 million related to increased professional fees associated with public company reporting and compliance requirements, and $0.4 million was primarily related to expenses associated with mergers and acquisition activities.

Depreciation and Amortization. Depreciation and amortization for the six months ended June 30, 2014 decreased $3.8 million, or 44% as compared to the six months ended June 30, 2013. Excluding Kildair’s depreciation expense in the six months ended June 30, 2013 of $3.8 million, depreciation and amortization expense was consistent between the periods.

Interest Expense, net

Three Months Ended June 30, 2014 compared to Three Months Ended June 30, 2013


	Three Months Ended June 30,				Increase/(Decrease)
	2014		2013		$			%
			($ in thousands)
Interest expense, net	$	4,034	$	6,960	$	(2,926	)		(42	)%

Interest Expense, net. Interest expense, net for the three months ended June 30, 2014 decreased $2.9 million, or 42%, as compared to the three months ended June 30, 2013. Of this decrease, $1.0 million was related to Kildair’s interest expense and $1.9 million was primarily due to lower working capital borrowing requirements and lower interest rate derivative obligations.

Six Months Ended June 30, 2014 compared to Six Months Ended June 30, 2013


	Six Months Ended June 30,				Increase/(Decrease)
	2014		2013		$			%
			($ in thousands)
Interest expense, net	$	9,423	$	14,379	$	(4,956	)		(34	)%

Interest Expense, net. Interest expense, net for the six months ended June 30, 2014 decreased $5.0 million, or 34%, as compared to the six months ended June 30, 2013. Excluding Kildair’s interest expense of $1.6 million, the remaining $3.4 million was primarily due to lower working capital borrowing requirements and lower interest rate derivative obligations.

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 (the “Credit Agreement”) and potential future issuances of additional partnership interests or debt securities are our primary sources of liquidity. At June 30, 2014, the Partnership had working capital of approximately $183.3 million.

Our Credit Agreement matures on October 30, 2018 and consists of two revolving credit facilities: (1) a $750.0 million working capital facility (the “working capital facility”) and (2) a $250.0 million acquisition facility (the “acquisition facility”).

As of June 30, 2014, the borrowing base under the Partnership’s working capital facility was approximately $332.0 million. As of June 30, 2014, working capital borrowings were $139.8 million and outstanding letters of credit were $27.7 million, providing us with approximately $164.5 million in undrawn borrowing capacity under the working capital facility.

As of June 30, 2014, the Partnership had $107.9 million in outstanding borrowings under our acquisition facility, resulting in $142.1 million in undrawn borrowing capacity under the acquisition facility.

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, inventory is reduced, accounts receivable are collected and converted into cash and debt is paid down. During the six months ended June 30, 2014, the amount the Partnership had drawn under the working capital facility fluctuated from a low of $115.0 million to a high of $424.7 million.

Certain of our trade credit providers have historically required us to obtain trade credit support from Axel Johnson. As of June 30, 2014, Axel Johnson provided us with approximately $13.7 million of outstanding trade guarantees. We believe that over a reasonable period of time we will be able to reduce, and eventually eliminate, the need for trade credit support from Axel Johnson. Pursuant to the omnibus agreement that we entered into in connection with the closing of the IPO, we agreed to use our commercially reasonable efforts to reduce, and eventually eliminate, the need for trade credit support from Axel Johnson. In order to assist us with a smooth transition with our trade credit providers following the completion of the IPO, pursuant to such omnibus agreement, Axel Johnson agreed to provide us with trade credit support, consistent with past practice, through December 31, 2016, if and to the extent such trade credit support is necessary in our reasonable judgment. We believe that the elimination of trade credit support from Axel Johnson after December 31, 2016 will not have a material adverse effect on our operations.

We believe that we will 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

In connection with the closing of our IPO on October 30, 2013, we entered into the Credit Agreement having the principal terms described below.

There are two revolving credit facilities under the Credit Agreement:

•

A working capital facility of up to $750.0 million to be used for working capital loans and letters of credit in the principal amount equal to the lesser of our borrowing base and $750.0 million. Our borrowing base is calculated as the sum of specified percentages of eligible cash collateral, eligible billed and unbilled accounts receivable, eligible inventory and other approved categories. Subject to certain conditions, the working capital facility may be increased by up to $200.0 million.

•

An acquisition facility of up to $250.0 million to be used for loans and letters of credit to fund capital expenditures and acquisitions related to our current businesses. Loans and letters of credit outstanding under the acquisition facility generally cannot exceed 65% of the fair market value of all of our appraised fixed assets. Subject to certain conditions, the acquisition facility may be increased by up to $200.0 million.

We and each of our subsidiaries, if not the borrower, are guarantors of all obligations under the Credit Agreement. All obligations under our Credit Agreement are secured by substantially all of our assets and substantially all of the assets of our subsidiaries.

Indebtedness under our Credit Agreement bears interest, at our option, at a rate per annum equal to either the Eurodollar Rate (which means the LIBOR Rate) for interest periods of one, two, three or six months plus a specified margin or an Alternate Base Rate plus a specified margin. The Alternate Base Rate is the highest of (a) the prime rate of interest announced from time to time by the agent bank as its “Base Rate” (b) 0.50% per annum above the Federal Funds rate as in effect from time to time and (c) the Eurodollar Rate for 1-month LIBOR as in effect from time to time plus 1.00% per annum.

The specified margin for the working capital facility under our Credit Agreement ranges from 1.00% to 1.50% for loans bearing interest at the Alternate Base Rate and from 2.00% to 2.50% for loans bearing interest at the Eurodollar Rate and for letters of credit issued under the working capital facility. The specified margin is calculated based upon how much of the working capital facility we utilize. In addition, we incur a commitment fee based on the unused portion of the working capital facility at a rate ranging from 0.375% to 0.50% per annum.

The specified margin for the acquisition facility under our Credit Agreement ranges 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 Eurodollar Rate and for letters of credit issued under the acquisition facility. The specified margin and the commitment fee for the acquisition facility is calculated quarterly based upon our consolidated total leverage ratio. In addition, we incur a commitment fee on the unused portion of the acquisition facility at a rate ranging from 0.375% to 0.50% per annum.

Our Credit Agreement matures in October 2018, at which point all amounts outstanding under the working capital facility and acquisition facility will become due. We are required to make prepayments under our Credit Agreement at any time when the aggregate amount of the outstanding loans and letters of credit under the working capital facility exceeds the aggregate amount of commitments in respect of such facility, or when the aggregate amount of outstanding loans and letters of credit under the acquisition facility exceeds the lesser of the aggregate amount of commitments in respect of such facility and 65% of the fair market value of the appraised assets, or, from the period of August 1^st to March 31^st each year, when the aggregate amount of the outstanding loans and letters of credit under the working capital facility plus the aggregate amount of working capital loans and letters of credit under the acquisition facility exceed the borrowing base. Mandatory prepayments also are required for certain sales of our assets. All loans repaid or prepaid may be reborrowed prior to the maturity date subject to satisfaction of the applicable conditions at the time of borrowing.

Our Credit Agreement prohibits us from making distributions to unitholders if any event of default, as defined in our Credit Agreement, occurs or would result from the distribution. In addition, our Credit Agreement contains various covenants that may limit, among other things, our ability to:

•

Grant liens;

•

Make certain loans or investments;

•

Incur additional indebtedness or guarantee other indebtedness;

•

Sell our assets; or

•

Acquire another company.

Our Credit Agreement also contains financial covenants requiring us to maintain:

•

Minimum consolidated net working capital of $35.0 million;

•

A minimum EBITDA to consolidated fixed charge coverage ratio of 1.2 to 1.0;

•

A maximum consolidated senior secured leverage to EBITDA ratio of 3.5 to 1.0 with respect to the aggregate amount of borrowings outstanding under the acquisition facility plus other funded secured indebtedness; and

•

A maximum consolidated total leverage to EBITDA ratio of 4.5 to 1.0 with respect to the aggregate amount of borrowings outstanding under the acquisition facility plus bonds and debentures and other funded indebtedness.

If any event of default exists under our Credit Agreement, the lenders will be able to accelerate the maturity of the Credit Agreement and exercise other rights and remedies. Each of the following would be an event of default:

•

Failure to pay, when due, any principal, interest, fees or other amounts after a specific cure period;

•

Failure of any representation or warranty to be true and correct in any material respect;

•

Failure to perform or otherwise comply with the covenants in the Credit Agreement or in other loan documents to which we are a borrower without a waiver or amendment;

•

Any default in the performance of any obligation or condition beyond the applicable grace period relating to any other indebtedness of more than $10.0 million;

•

A judgment default for monetary judgments exceeding $10.0 million;

•

A change of control as defined below;

•

A bankruptcy or insolvency event involving us or any of our subsidiaries; and

•

Failure of the lenders for any reason to have a first perfected security interest in the security pledged by us or any of the security becomes unenforceable or invalid.

A change of control is the occurrence of any of the following events: (a) Antonia A. Johnson, together with her spouse, children, grandchildren and heirs (and any trust of which any of the foregoing (or any combination thereof) constitute at least 80% of the then current beneficiaries) cease to own and control more than 50% of the total voting power of each class of outstanding equity interests of our General Partner, (b) our General Partner ceases to own and control all of the general partner interests in us, and (c) we cease to own and control all of each class of outstanding equity interests of each subsidiary that is a borrower or a guarantor under our Credit Agreement.

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements.

Capital Expenditures

Our terminals require investments to 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.

During the six months ended June 30, 2014, we incurred a total of approximately $1.3 million in maintenance capital expenditures and we spent $0.3 million for expansion and/or upgrades of our terminals. We anticipate that future maintenance capital expenditures will be funded with cash generated by operations and that future expansion capital requirements will be provided through long-term borrowings or other debt financings and/or equity offerings.

Cash Flows


	Six Months Ended June 30,
	2014			2013
	($ in thousands)
Net cash provided by operating activities	$	228,132		$	118,348
Net cash used in investing activities	$	(1,661	)	$	(6,106	)
Net cash used in financing activities	$	(226,231	)	$	(115,435	)

Operating Activities

Net cash provided by operating activities for the six months ended June 30, 2014 was approximately $228.1 million and primarily resulted from a decrease of $200.0 million in inventory and $86.5 million in accounts receivable, as levels normally decrease when the Northeast United States exits out of the winter season and net income of $65.8 million. The cash flow from operations was partially offset by a decrease of $103.0 million in accounts payable and accrued liabilities, primarily due to timing of invoice payments for product purchases as the Northeast United States exits out of the winter season, as well as an increase of $44.4 million in derivative instruments primarily relating to the recognition of natural gas fixed forward net commitments during the period.

Net cash provided by operating activities for the six months ended June 30, 2013 was approximately $118.3 million. Cash flow from operations was driven by a decrease of $133.0 million in inventory and $59.0 million in accounts receivable, as levels normally decrease when the Northeast United States exits out of the winter season. The cash flow from operations was partially offset by a decrease of $80.0 million in accounts payable and accrued liabilities, primarily due to timing of invoice payments for product purchases as the Northeast United States exits out of the winter season, as well as an increase of $24.8 million in derivative instruments primarily relating to the recognition of natural gas fixed forward net commitments during the period.

Investing Activities

Net cash used in investing activities for the six months ended June 30, 2014 was approximately $1.7 million and consisted primarily of capital expenditure projects across our terminal system.

Net cash used in investing activities for the six months ended June 30, 2013 was approximately $6.1 million of which $8.1 million relates to terminal capital expenditure projects, which includes $5.7 million of capital expenditures relating to Kildair activities. This was offset by the receipt of $1.9 million from insurance proceeds.

Financing Activities

Net cash used in financing activities for the six months ended June 30, 2014 was approximately $226.2 million and primarily resulted from $211.8 million of net payments under the Credit Agreement due to reduced financing needs primarily as a result of lower inventory and accounts receivables levels, and distributions to unitholders of $14.0 million.

Net cash used in financing activities for the six months ended June 30, 2013 was approximately $115.4 million and primarily resulted from $101.9 million of net payments under the Predecessor’s credit agreements due to reduced borrowing needs as a result of lower inventory and accounts receivables levels and a $22.5 million dividend to Axel Johnson. This was partially offset by a $10.0 million advance from Axel Johnson, which was reclassified into equity upon the successful completion of the acquisition of the oil terminal in Bridgeport, Connecticut.

Provision for Income Taxes

Prior to the completion of the IPO, the Predecessor prepared its income tax provision as if it operated as a stand-alone taxpayer for all periods presented in accordance with a pre-existing tax sharing agreement between the Predecessor and the Parent. As of the completion of the IPO on October 30, 2013, the Partnership is now treated as a pass-through entity for U.S. federal income tax purposes. As a result, substantially all income, expenses, gains, losses and tax credits generated flow through to the Partnership’s unitholders and, accordingly, do not result in a provision for U.S. federal income taxes and certain state income taxes.

Impact of Inflation

Inflation in the United States and Canada has been relatively low in recent years and did not have a material impact on our results of operations for the six months ended June 30, 2014 and 2013.

New Accounting Guidance

Other Accounting Standards or Updates Not Yet Effective

We have evaluated the accounting guidance recently issued and have determined that these standards or updates will not have a material impact on our financial position, results of operations, or cash flows.

Critical Accounting Policies and Estimates

“Part I, Item, 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations” discusses our consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of these 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 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 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.

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 and credit risk. We utilize various derivative instruments to manage exposure to commodity risk and forward starting swaps to manage exposure to interest rate risk.

Commodity Price Risk

We use various financial instruments to hedge our commodity price risk. We sell our refined products and natural gas primarily in the Northeast. This geographic focus is a key factor in how we choose the most appropriate financial instruments to hedge our positions.

We hedge our refined products positions primarily with a combination of futures contracts that trade on the New York Mercantile Exchange, or NYMEX, and fixed-for-floating price swaps that are bilateral contracts that are traded “over-the-counter.” 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 oils futures contracts. 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

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.

For natural gas, there are no quality differences that need to be considered when hedging. Our primary hedging requirements relate to fixed price and basis (location) exposure. We largely hedge our natural gas fixed price exposure using fixed-for-floating price swaps that trade on the Intercontinental Exchange (or “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 physically by using forward purchases or sales.

The following table presents total realized and unrealized (losses) and gains on derivative instruments utilized for commodity risk management purposes. Such amounts are included in cost of products sold for the three and six months ended June 30, 2014 and 2013:


	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
				Predecessor						Predecessor
Refined products contracts	$	136		$	18,603		$	9,997		$	12,063
Natural gas contracts		(9,121	)		(2,891	)		(22,814	)		(10,212	)

Total	$	(8,985	)	$	15,712		$	(12,817	)	$	1,851

Substantially all of our commodity derivative contracts outstanding as of June 30, 2014 will settle prior to December 31, 2015.

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. At June 30, 2014, the notional value of our cash flow hedges was composed of base notional amounts of $100.0 million expiring through January 2015. 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. Borrowings under our Credit Agreement will bear interest, at our option, at a rate per annum equal to the Eurodollar Rate (which means the LIBOR Rate as determined from indices from the British Bankers Association) and the Alternate Base Rate which means the highest of (a) the prime rate of interest announced from time to time by the agent as its “Base Rate,” (b) 0.50% per annum above the Federal Funds Rate as in effect from time to time and (c) the Eurodollar Rate for 1-month LIBOR as in effect from time-to-time plus 1.00% per annum, depending on which facility is being used. During the two year period ended June 30, 2014, we hedged approximately 42% of our floating rate debt with fixed-for-floating interest rate swaps. We report unrealized gains and losses on the interest rate swaps as a component of accumulated other comprehensive gain or loss, net of taxes, which is reclassified to earnings as interest expense when payments are made. We expect to continue to utilize interest rate swaps to manage our exposure to LIBOR interest rates.

Derivative Instruments

The following tables present all of our financial assets and financial liabilities measured at fair value on a recurring basis as of June 30, 2014:


	As of June 30, 2014
			Quoted		Significant
			Prices in		Other		Significant
			Active		Observable		Unobservable
	Fair Value		Markets		Inputs		Inputs
	Measurement		Level 1		Level 2		Level 3
Financial assets:
Commodity exchange contracts	$	5	$	5	$	—	$	—
Commodity fixed forwards		55,818		—		55,818		—
Commodity swaps and options		65		—		65		—

Commodity derivatives		55,888		5		55,883		—
Interest rate swaps		—		—		—		—

Total	$	55,888	$	5	$	55,883	$	—

Financial liabilities:
Commodity exchange contracts	$	—	$	—	$	—	$	—
Commodity fixed forwards		74,842		—		74,842		—
Commodity swaps and options		69		—		69		—

Commodity derivatives		74,911		—		74,911		—
Interest rate swaps		1,254		—		1,254		—

Total	$	76,165	$	—	$	76,165	$	—

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 volatility of 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. Controls include volumetric, value at risk and stop loss limits on discretionary positions as well as contract term limits. Our Chief Risk Officer 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 value at risk to monitor and control 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, and accepting personal guarantees and various 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.

Item 4. Controls and Procedures

Disclosure Controls and Procedures

Our management, with the participation of our Chief Executive Officer and our Chief Operating Officer/Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures as of June 30, 2014. 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 Partnership’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 June 30, 2014, our Chief Executive Officer and Chief Operating Officer/Chief Financial Officer concluded that, as of such date, our disclosure controls and procedures were effective at the reasonable assurance level.

Internal Control Over Financial Reporting

There have been no changes in our system of internal control over financial reporting during the six months ended June 30, 2014 that have materially affected, or are reasonably likely to materially affect, the Partnership’s internal control over financial reporting.

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 2013 Annual Report, which could materially affect our business, financial condition or future results.

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

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

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).


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

10.1*	—	Form of Phantom Unit Agreement (Performance Based Vesting).

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 Rule 406T of Regulation S-T, the documents formatted in XBRL (Extensible Business Reporting Language) and attached as Exhibit 101 to this report are deemed not filed or part of a registration statement or prospectus for purposes of Section 11 or 12 of the Securities Act, are deemed not filed for purposes of Section 18 of the Exchange Act, and otherwise are not subject to liability under these sections.

SIGNATURES

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


	SPRAGUE RESOURCES LP

	By:	Sprague Resources GP LLC,
		Its General Partner

Date: August 13, 2014		/s/ 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)

EXHIBIT INDEX

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


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

10.1*	—	Form of Phantom Unit Agreement (Performance Based Vesting).

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.

***