Edgar Filing: Sprague Resources LP

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Non-accelerated filer

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Smaller reporting company

10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 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 10,106,037 common units and approximately 10,071,970 subordinated units outstanding as of November 10, 2014

Table of Contents


		Page
PART I—FINANCIAL INFORMATION

Item 1.	Financial Statements:
	Consolidated Balance Sheets as of September 30, 2014 and December 31, 2013		3
	Unaudited Consolidated Statements of Operations for the three and nine months ended September 30, 2014 and September 30, 2013		4
	Unaudited Consolidated Statements of Comprehensive (Loss) Income for the three and nine months ended September 30, 2014 and September 30, 2013		5
	Unaudited Consolidated Statement of Unitholders’ Equity for the nine months ended September 30, 2014		6
	Unaudited Consolidated Statements of Cash Flows for the nine months ended September 30, 2014 and September 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)


	September 30, 2014			December 31, 2013
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	385		$	998
Accounts receivable, net		153,492			240,779
Inventories		269,734			348,107
Fair value of derivative assets		96,730			65,098
Deferred income taxes		1,807			2,207
Other current assets		49,291			25,369

Total current assets		571,439			682,558
Property, plant, and equipment, net		113,813			116,807
Intangibles and other assets, net		14,703			16,842
Goodwill		37,383			37,383

Total assets	$	737,338		$	853,590


Liabilities and unitholders’ equity
Current liabilities:
Accounts payable	$	103,971		$	175,187
Accrued liabilities		40,317			33,415
Fair value of derivative liabilities		103,589			130,954
Due to General Partner and affiliates		11,335			4,760
Current portion of long-term debt		150,153			126,652
Current portion of capital leases		234			193

Total current liabilities		409,599			471,161

Commitments and contingencies (Note 10)		—			—

Long-term debt		241,647			332,848
Long-term capital leases		3,009			3,067
Other liabilities		13,877			15,015
Due to General Partner		863			—
Deferred income taxes		1,629			1,540

Total liabilities		670,624			823,631

Unitholders’ equity:
Common unitholders - public (8,526,084 units and 8,506,666 units issued and outstanding, as of September 30, 2014 and December 31, 2013, respectively)		142,258			127,496
Common unitholders - affiliated (1,571,970 units issued and outstanding)		(10,122	)		(12,854	)
Subordinated unitholders - affiliated (10,071,970 units issued and outstanding)		(64,859	)		(82,356	)
Accumulated other comprehensive loss, net of tax		(563	)		(2,327	)

Total unitholders’ equity		66,714			29,959

Total liabilities and unitholders’ equity	$	737,338		$	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 September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
				Predecessor						Predecessor
Net sales	$	728,821		$	940,275		$	3,474,985		$	3,407,048
Cost of products sold		708,490			914,574			3,311,849			3,282,438

Gross margin		20,331			25,701			163,136			124,610
Operating costs and expenses:
Operating expenses		11,626			12,844			37,504			40,444
Selling, general and administrative		13,277			12,633			48,670			39,689
Depreciation and amortization		2,383			4,034			7,070			12,471

Total operating costs and expenses		27,286			29,511			93,244			92,604


Operating (loss) income		(6,955	)		(3,810	)		69,892			32,006

Other (expense) income		—			(215	)		—			601
Interest income		122			261			388			521
Interest expense		(4,241	)		(7,207	)		(13,930	)		(21,846	)


(Loss) income before income taxes		(11,074	)		(10,971	)		56,350			11,282
Income tax benefit (provision)		356			4,560			(1,227	)		(6,078	)

Net (loss) income	$	(10,718	)	$	(6,411	)	$	55,123		$	5,204


Net (loss) income per limited partner unit:
Common - basic	$	(0.53	)				$	2.73
Common - diluted	$	(0.53	)				$	2.73
Subordinated - basic and diluted	$	(0.53	)				$	2.73
Units used to compute net (loss) income per limited partner unit:
Common - basic		10,091,388						10,085,058
Common - diluted		10,091,388						10,120,935
Subordinated - basic and diluted		10,071,970						10,071,970

Distribution declared per common and subordinated units	$	0.4425					$	1.2825

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 September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
				Predecessor						Predecessor
Net (loss) income	$	(10,718	)	$	(6,411	)	$	55,123		$	5,204
Other comprehensive income (loss), net of tax:
Unrealized gain (loss) on interest rate swaps
Net gain (loss) arising in the period		45			(165	)		(54	)		(303	)
Reclassification adjustment related for losses realized in income		631			1,292			1,864			3,806

Net change in unrealized loss on interest rate swaps		676			1,127			1,810			3,503
Tax effect		(17	)		(452	)		(46	)		(1,408	)

		659			675			1,764			2,095
Foreign currency translation adjustment		—			853			—			(1,812	)
Unrealized gain (loss) on inter-entity long-term foreign currency transactions		—			1,313			—			(2,501	)

Other comprehensive income (loss)		659			2,841			1,764			(2,218	)

Comprehensive (loss) income	$	(10,059	)	$	(3,570	)	$	56,887		$	2,986

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

Sprague Resources LP

Unaudited Consolidated Statements of Unitholders’ Equity

(in thousands)


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

Partnership net income		23,280			4,299			27,544			—			55,123
Other comprehensive income		—			—			—			1,764			1,764
Distribution to unitholders		(9,584	)		(1,764	)		(11,307	)		—			(22,655	)
Unit-based compensation		1,124			207			1,328			—			2,659
Repurchased units withheld for employee tax obligation		(58	)		(10	)		(68	)		—			(136	)

Balance at September 30, 2014	$	142,258		$	(10,122	)	$	(64,859	)	$	(563	)	$	66,714

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

Sprague Resources LP

Unaudited Consolidated Statements of Cash Flows

(in thousands)


	Nine Months Ended September 30,
	2014			2013
				Predecessor
Cash flows from operating activities
Net income	$	55,123		$	5,204
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		9,120			15,056
Provision for doubtful accounts		2,703			627
Gain on sale of assets		(61	)		(10	)
Gain on insurance recovery		—			(777	)
Deferred income taxes		441			(4,341	)
Non-cash unit-based compensation		5,267			—
Changes in assets and liabilities:
Accounts receivable		84,062			56,818
Inventories		78,373			144,242
Prepaid expenses and other assets		(23,922	)		(80	)
Fair value of commodity derivative instruments		(57,186	)		(5,142	)
Due to General Partner and affiliates		7,812			—
Accounts payable, accrued liabilities and other		(67,829	)		(61,669	)

Net cash provided by operating activities		93,903			149,928


Cash flows from investing activities
Purchases of property, plant and equipment		(3,606	)		(17,074	)
Proceeds from property insurance settlement		—			1,867
Business acquisition		—			(20,700	)
Proceeds from sale of assets		4			168

Net cash used in investing activities		(3,602	)		(35,739	)


Cash flows from financing activities
Net payments under credit agreements		(67,700	)		(82,622	)
Payments on capital lease liabilities and term debt		(148	)		(507	)
Payments on long-term terminal obligations		(422	)		(288	)
Debt issuance costs		—			(495	)
Capital contribution from parent		—			10,000
Dividend paid to Parent		—			(40,000	)
Distribution to unitholders		(22,655	)		—
Repurchased units withheld for employee tax obligation		(136	)		—
Net increase (decrease) in payable to Parent		147			(494	)

Net cash used in financing activities		(90,914	)		(114,406	)

Effect of exchange rate changes on cash balances held in foreign currencies		—			(161	)

Net change in cash and cash equivalents		(613	)		(378	)
Cash and cash equivalents, beginning of period		998			3,691

Cash and cash equivalents, end of period	$	385		$	3,313


Supplemental disclosure of cash flow information
Cash paid for interest	$	12,163		$	17,670
Cash paid for taxes	$	1,320		$	3,206

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 17 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 segment primarily includes the purchase and distribution of coal.

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 9047-1137 Quebec Inc. (“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. See Note 2-Initial Public Offering.

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 Kildair, whose primary business includes the storage and handling of customer-owned crude oil, as well as the marketing and distribution of residual fuel oil and asphalt. On October 1, 2012, our Predecessor acquired control of Kildair, 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. 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.

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 September 30, 2014 and December 31, 2013 and the consolidated results of operations and cash flows for the three and nine months ended September 30, 2014 and 2013, respectively.

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 statements, included in the 2013 Annual Report, and are the same as are used in preparing these unaudited interim consolidated financial statements.

The unaudited results of operations for the interim periods reported are not necessarily indicative of results to be expected for the full year. Demand for some of the Partnership’s refined petroleum products, specifically heating oil and residual oil for space heating purposes, and to a lesser extent natural gas, are generally higher during the first and fourth quarters of the calendar year which may result in significant fluctuations in the Partnership’s quarterly operating results.

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 September 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 Resources LP

Notes to Unaudited Consolidated Financial Statements

(in thousands unless otherwise stated)

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. IDR 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.

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 income of Kildair included in the Predecessor’s Consolidated Statements of Operations for the three and nine months ended September 30, 2013 are as follows:


	Three Months Ended September 30, 2013		Nine Months Ended September 30, 2013
Net sales	$	194,146	$	455,731
Net income (loss)		3,902		(219	)

4. Accumulated Other Comprehensive Loss, Net of Tax

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


	September 30, 2014			December 31, 2013
Cumulative change in fair value of interest rate swaps, net of tax	$	(563	)	$	(2,327	)

Sprague Resources LP

Notes to Unaudited Consolidated Financial Statements

(in thousands unless otherwise stated)

5. Inventories


	September 30, 2014		December 31, 2013
Petroleum and related products	$	264,580	$	344,403
Coal		4,091		1,886
Natural gas		1,063		1,818

Inventories	$	269,734	$	348,107

Due to changing market conditions, the Partnership recorded a provision of $9.4 million and $1.0 million as of September 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


	September 30, 2014		December 31, 2013
Credit agreement - current	$	150,153	$	126,652
Credit agreement - long term		241,647		332,848

Total	$	391,800	$	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 September 30, 2014 and December 31, 2013, working capital facility borrowings were $261.9 million and $351.6 million, respectively, and outstanding letters of credit were $45.6 million and $73.4 million, respectively. The working capital facility is subject to borrowing base reporting and as of September 30, 2014 and December 31, 2013, had a borrowing base of $481.5 million and $573.8 million, respectively. As of September 30, 2014, excess availability under the working capital facility was $174.0 million.

As of September 30, 2014 and December 31, 2013, acquisition line borrowings were $129.9 and $107.9 million, respectively. As of September 30, 2014, excess availability under the acquisition facility was $120.1 million.

The weighted average interest rate at September 30, 2014 and December 31, 2013 was 3.0% and 2.9%, respectively. The current portion of amounts outstanding on the Credit Agreement at September 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 September 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 employee costs and related employee benefits and other overhead costs supporting the Partnership’s operations which amounted to $13.4 million and $58.5 million for the three and nine months ended September 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 $12.2 million and $4.8 million as of September 30, 2014 and December 31, 2013 respectively.

Sprague Resources LP

Notes to Unaudited Consolidated Financial Statements

(in thousands unless otherwise stated)

During the nine months ended September 30, 2013, the Predecessor paid cash dividends to the Parent of $40.0 million as permitted by the Predecessor’s credit agreement and received a capital contribution of $10.0 million from the Parent in connection with the acquisition of the oil terminal in Bridgeport, Connecticut.

During the nine months ended September 30, 2013, the Parent charged the Predecessor $1.0 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 for the period October 1, 2012 to 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 nine months ended September 30, 2014 and 2013 is presented in the table below:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
				Predecessor						Predecessor
	(in thousands)						(in thousands)
Net sales:
Refined products	$	666,538		$	879,691		$	3,187,482		$	3,148,743
Natural gas		53,376			49,623			255,058			222,704
Materials handling		7,739			7,185			24,140			21,713
Other operations		1,168			3,776			8,305			13,888

Net sales	$	728,821		$	940,275		$	3,474,985		$	3,407,048

Adjusted gross margin(1):
Refined products	$	21,656		$	25,447		$	81,092		$	78,593
Natural gas		4,604			4,415			42,614			28,401
Materials handling		7,765			7,181			24,158			21,700
Other operations		222			1,000			790			3,369

Adjusted gross margin		34,247			38,043			148,654			132,063
Reconciliation to gross margin(2):
Deduct: total commodity derivative gains (losses) included in net income (loss)(3)		18,967			(23,051	)		6,150			(21,200	)
Add: realized commodity derivative (gains) losses included in net income (loss)(3)		(32,883	)		10,709			8,332			13,747

Gross margin		20,331			25,701			163,136			124,610

Operating costs and expenses not allocated to operating segments:
Operating expenses		11,626			12,844			37,504			40,444
Selling, general and administrative		13,277			12,633			48,670			39,689
Depreciation and amortization		2,383			4,034			7,070			12,471

Total operating costs and expenses		27,286			29,511			93,244			92,604

Operating (loss) income		(6,955	)		(3,810	)		69,892			32,006
Other (expense) income		—			(215	)		—			601
Interest income		122			261			388			521
Interest expense		(4,241	)		(7,207	)		(13,930	)		(21,846	)
Income tax benefit (provision)		356			4,560			(1,227	)		(6,078	)

Net (loss) income	$	(10,718	)	$	(6,411	)	$	55,123		$	5,204

(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 nine months ended September 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 $70.5 million for the three months ended September 30, 2014 and 2013, and $3.2 million and $198.0 million for the nine months ended September 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, materials handling, or other operating segments. There are no significant fixed assets attributable to the natural gas reportable segment.

As of September 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 and Cash Equivalents, Accounts Receivable and Debt

As of September 30, 2014 and December 31, 2013, the carrying amounts of cash and cash equivalents and accounts receivable approximated fair value because of the short maturity of these instruments. As of September 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 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 September 30, 2014 will settle prior to March 31, 2016.

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.

Sprague Resources LP

Notes to Unaudited Consolidated Financial Statements

(in thousands unless otherwise stated)

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

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


	As of September 30, 2014
	Fair Value Measurement		Quoted Prices in Active Markets Level 1		Significant Other Observable Inputs Level 2		Significant Unobservable Inputs Level 3
Financial assets:
Commodity exchange contracts	$	119	$	119	$	—	$	—
Commodity fixed forwards		96,389		—		96,389		—
Commodity swaps and options		106		—		106		—

Commodity derivatives		96,614		119		96,495		—
Interest rate swaps		116		—		116		—

Total	$	96,730	$	119	$	96,611	$	—

Financial liabilities:
Commodity exchange contracts	$	—	$	—	$	—	$	—
Commodity fixed forwards		102,789		—		102,789		—
Commodity swaps and options		106		—		106		—

Commodity derivatives		102,895		—		102,895		—
Interest rate swaps		694		—		694		—

Total	$	103,589	$	—	$	103,589	$	—


	As of December 31, 2013
	Fair Value Measurement		Quoted Prices in Active Markets Level 1		Significant Other Observable Inputs Level 2		Significant Unobservable Inputs 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	$	—

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	$	—

Sprague Resources LP

Notes to Unaudited Consolidated Financial Statements

(in thousands unless otherwise stated)

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 September 30, 2014 and December 31, 2013 follows:


	As of September 30, 2014
	Gross Amounts of Recognized Assets/ Liabilities			Gross Amounts Offset in the Balance Sheet		Amounts of Assets/ Liabilities in Balance Sheet			Gross Amount Not Offset in the Balance Sheet						Net Amount
	Gross Amounts of Recognized Assets/ Liabilities			Gross Amounts Offset in the Balance Sheet		Amounts of Assets/ Liabilities in Balance Sheet			Financial Instruments			Cash Collateral Posted			Net Amount
Commodity derivative assets	$	96,614		$	—	$	96,614		$	(9,317	)	$	(2,453	)	$	84,844
Interest rate swap derivative assets		116			—		116			—			—			116

Fair value of derivative assets	$	96,730		$	—	$	96,730		$	(9,317	)	$	—		$	84,960

Commodity derivative liabilities	$	(102,895	)	$	—	$	(102,895	)	$	9,317		$	—		$	(93,578	)
Interest rate swap derivative liabilities		(694	)		—		(694	)		—			—			(694	)

Fair value of derivative liabilities	$	(103,589	)	$	—	$	(103,589	)	$	9,317		$	—		$	(94,272	)


	As of December 31, 2013
	Gross Amounts of Recognized Assets/ Liabilities			Gross Amounts Offset in the Balance Sheet		Amounts of Assets/ Liabilities in Balance Sheet			Gross Amount Not Offset in the Balance Sheet						Net Amount
	Gross Amounts of Recognized Assets/ Liabilities			Gross Amounts Offset in the Balance Sheet		Amounts of Assets/ Liabilities in Balance Sheet			Financial Instruments			Cash Collateral 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)

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


	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
				Predecessor						Predecessor
Refined products contracts	$	30,197		$	(9,142	)	$	40,194		$	2,921
Natural gas contracts		(11,230	)		(13,909	)		(34,044	)		(24,121	)

Total	$	18,967		$	(23,051	)	$	6,150		$	(21,200	)

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

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


	As of September 30, 2014						As of December 31, 2013
	Refined Products (Barrels)			Natural Gas (MMBTUs)			Refined Products (Barrels)			Natural Gas (MMBTUs)
Long contracts		10,526			95,099			9,250			100,119
Short contracts		(12,454	)		(64,979	)		(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 September 30, 2014, the Partnership held three interest rate swap agreements with a notional value of $100.0 million with swap periods that expire in January 2015; six interest rate swaps with a total notional value of $175.0 million whose swap periods begin in January 2015, expiring in January 2016; and five interest rate swaps with a total notional value of $150.0 million whose swap periods begin in January 2016, expiring in January 2017.

There was no material ineffectiveness determined for the cash flow hedges for the three and nine months ended September 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 September 30, 2014, the amount of unrealized losses, net of tax, expected to be reclassified to earnings during the following twelve-month period was $0.7 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 nine months ended September 30, 2014 and 2013:


	Three Months Ended September 30, 2014					Nine Months Ended September 30, 2014
	Amount of Derivative Gain Recognized in OCL			Amount of Derivative Loss Reclassified From Accumulated OCL Into Income		Amount of Derivative Loss Recognized in OCL		Amount of Derivative Loss Reclassified From Accumulated OCL Into Income
Interest rate swaps	$	(45	)	$	631	$	54	$	1,864

	Three Months Ended September 30, 2013					Nine Months Ended September 30, 2013
	Predecessor					Predecessor
	Amount of Derivative Loss Recognized in OCL			Amount of Derivative Loss Reclassified From Accumulated OCL Into Income		Amount of Derivative Loss Recognized in OCL		Amount of Derivative Loss Reclassified From Accumulated OCL Into Income
Interest rate swaps	$	165		$	1,292	$	303	$	3,806

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 (estimated grant date fair value of $0.1 million) 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 was less than $0.1 million as of September 30, 2014, which is expected to be recognized over a period of approximately 25 months.

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 31, 2015 and 9,919 on March 31, 2016. Total unrecognized compensation related to phantom units was $0.3 million as of September 30, 2014 which is expected to be recognized over a period of approximately 18 months. 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.

Sprague Resources LP

Notes to Unaudited Consolidated Financial Statements

(in thousands unless otherwise stated)

On July 11, 2014, the Board of Directors of the General Partner approved the 2014 annual bonus program, which is provided to substantially all employees and will be settled in cash for the majority of participants with others receiving a combination of cash and common units. In previous years all participants were compensated only in cash. The Partnership records the entire expected bonus payment as a liability until a grant date has been established and awards finalized, which occurs in the first quarter of the following year. The Partnership estimates that approximately $0.3 million and $2.6 million of the annual bonus expense recorded during the three and nine months ended September 30, 2014 will be settled in common units.

On July 11, 2014, the Board of Directors of the General Partner granted under the 2013 LTIP performance-based phantom unit awards to key employees; previously the Partnership’s long-term incentive program was settled solely in cash. These units vest over a three year period if certain performance criteria are met. Upon vesting, a holder of performance-based phantom units is entitled to receive a number of common units of the Partnership equal to a percentage (0 percent to 200 percent) of the target phantom units granted, based on our total unitholder return over the vesting period, compared with the total unitholder return of a peer group of other master limited partnership energy companies over the same period.

The Partnership’s performance-based phantom unit awards are equity awards with both service and market-based conditions, which results in the compensation cost for these awards being recognized over the requisite service period, provided that the requisite service period is fulfilled, regardless of when, if ever, the market based conditions are satisfied. The fair value of these performance-based phantom units was estimated to be $5.5 million, (weighted average of $36.34 per unit), based on a Monte Carlo model that estimated the most likely outcome based on the terms of the award. The key inputs in the model include the market price of the Partnership’s common units as of the valuation date, the historical volatility of the market price of the Partnership’s common units, the historical volatility of the market price of the common units or common stock of the peer companies and the correlation between changes in the market price of the Partnership’s common units and those of the peer companies. Total unrecognized compensation cost related to the performance-based phantom units totaled $3.1 million as of September 30, 2014, which is expected to be recognized over a period of approximately 27 months. Performance based phantom units accrue dividend equivalents which are recorded as liabilities over the requisite service period and are paid in cash upon vesting of the underlying performance-based phantom unit. No dividends are paid prior to vesting on performance based phantom units granted.

A summary of the Partnership’s unit awards subject to vesting for the nine months ended September 30, 2014, is set forth below:


	Restricted Units				Phantom Units				Performance Based Phantom Units
	Units		Weighted Average Grant Date Fair Value (per unit)		Units		Weighted Average Grant Date Fair Value (per unit)		Units			Weighted Average Grant Date Fair Value (per unit)
Nonvested at December 31, 2013		6,666	$	17.33	$	—	$	—		—		$	—
Granted		—		—		23,685		20.16		151,099			36.34
Forfeited		—		—		—		—		(3,000	)		36.34

Nonvested at September 30, 2014		6,666	$	17.33		23,685	$	20.16		148,099		$	36.34

Unit-based compensation recorded in unitholders’ equity for the three and nine months ended September 30, 2014 was $2.1 million and $2.7 million, respectively, and is included in selling, general and administrative expenses.

Sprague Resources LP

Notes to Unaudited Consolidated Financial Statements

(in thousands unless otherwise stated)

12. Earnings Per Unit

Earnings per unit applicable to limited partners (including subordinated unitholders) is computed by dividing limited partners’ interest in net income (loss), after deducting any incentive distributions, by the weighted-average number of outstanding common and subordinated units. The Partnership’s net income (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 (loss) allocations used in the calculation of earnings per unit.

In addition to the common and subordinated units, the Partnership has also identified the IDRs, unvested performance unit awards 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.

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


	Three Months Ended September 30, 2014		Nine Months Ended September 30, 2014
Weighted average limited partner common units - basic		10,091,388		10,085,058
Dilutive effect of unvested restricted and phantom units		—		35,877

Weighted average limited partner common units - dilutive		10,091,388		10,120,935

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


	Three Months Ended September 30, 2014
	Common Units			Subordinated Units			Total
	(in thousands, except for per unit amounts)
Net loss							$	(10,718	)

Distributions declared	$	4,502		$	4,457		$	8,959
Assumed net loss from operations after distributions		(9,866	)		(9,811	)		(19,677	)

Assumed net loss to be allocated	$	(5,364	)	$	(5,354	)	$	(10,718	)

Loss per unit - basic	$	(0.53	)	$	(0.53	)
Loss per unit - diluted	$	(0.53	)	$	(0.53	)


	Nine Months Ended September 30, 2014
	Common Units		Subordinated Units		Total
	(in thousands, except for per unit amounts)
Net income					$	55,123

Distributions declared	$	12,984	$	12,918	$	25,902
Assumed net income from operations after distributions		14,595		14,626		29,221

Assumed net income to be allocated	$	27,579	$	27,544	$	55,123

Income per unit - basic	$	2.73	$	2.73
Income per unit - diluted	$	2.73	$	2.73

Sprague Resources LP

Notes to Unaudited Consolidated Financial Statements

(in thousands unless otherwise stated)

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.

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 was paid on August 14, 2014, to unitholders of record on August 8, 2014.

14. Subsequent Events

Partnership Distribution

On October 29, 2014 the Partnership declared a cash distribution totaling $8.9 million, or $0.4425 per unit for the three months ended September 30, 2014. Such distribution will be paid on November 14, 2014, to unitholders of record on November 10, 2014.

Acquisition of Metromedia Gas & Power, Inc.

On October 1, 2014, the Partnership completed its purchase of Metromedia Gas & Power Inc’s (“Metromedia Energy”) natural gas marketing and electricity brokerage business for $22.0 million, not including the purchase of natural gas inventory, utility security deposits and other adjustments. Total consideration at closing was $32.8 million. Metromedia Energy markets natural gas and brokers electricity to commercial, industrial and municipal consumers in the Northeast and Mid-Atlantic, providing customers with approximately 15 Bcf of natural gas and assisting in the procurement of approximately 150 Megawatts of power demand annually. Metromedia Energy’s natural gas portfolio includes more than 8,500 accounts who are served by over thirty utilities from twelve interstate pipeline connections between Virginia and Maine and as far west as Ohio. Metromedia provides electricity brokerage services for more than 7,000 commercial and industrial accounts behind forty-six utilities across seventeen states and Washington D.C.

The acquisition was accounted for as a business combination and was financed with borrowings under the Partnership’s credit facility. The allocation of the purchase price to the assets acquired and liabilities assumed will be finalized as the Partnership receives additional information regarding the acquisition, including a final valuation of the assets purchased.

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 September 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:

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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.

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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.

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

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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.

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

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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.

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

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

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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.

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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.

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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.

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

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

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Any disruptions in our labor force could affect our business.

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

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

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If expected synergies from acquisitions do not materialize or we fail to successfully integrate new businesses into our existing businesses, our results from the acquired operations could be adversely affected.

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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.

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

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

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The condition of credit markets may adversely affect us.

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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.

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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.

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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 nine months ended September 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 17 refined products and materials handling terminals strategically located throughout the Northeast that have a combined in service storage capacity of approximately 10.0 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 approximately 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.”

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 September 30, 2014 and 2013, we sold approximately 231.1 million and 308.1 million gallons of refined products, respectively, and our refined products segment accounted for 63% and 67% of our adjusted gross margin, respectively. For the nine months ended September 30, 2014 and 2013, we sold approximately 1.0 billion and 1.1 billion gallons of refined products, respectively, and our refined products segment accounted for 54% and 59% of our adjusted gross margin, respectively.

We also purchase, sell and distribute natural gas to approximately 5,500 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 September 30, 2014 and 2013, we sold 10.3 Bcf and 10.0 Bcf of natural gas respectively, and our natural gas segment accounted for 13% and 12% of our adjusted gross margin respectively. For the nine months ended September 30, 2014 and 2013, we sold 38.3 Bcf of natural gas for both periods and our natural gas segment accounted for 29% and 22% 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 September 30, 2014, we offloaded, stored and/or prepared for delivery 0.7 million short tons of products and 55.4 million gallons of liquid materials. For the three months ended September 30, 2013, we offloaded, stored and/or prepared for delivery 0.5 million short tons of products and 54.5 million gallons of liquid materials. For the three months ended September 30, 2014 and 2013, our materials handling segment accounted for 23% and 19% of our adjusted gross margin, respectively. For the nine months ended September 30, 2014, we offloaded, stored and/or prepared for delivery 2.0 million short tons of products and 167.6 million gallons of liquid materials. For the nine months ended September 30, 2013, we offloaded, stored and/or prepared for delivery 1.6 million short tons of products and 177.0 million gallons of liquid materials. For the nine months ended September 30, 2014 and 2013, our materials handling segment accounted for 16% of our adjusted gross margin, for both periods.

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

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 Kildair, whose primary business includes the storage and handling of customer-owned crude oil, as well as the marketing and distribution of residual fuel oil and asphalt. On October 1, 2012, our Predecessor acquired control of Kildair, 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.

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 September 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.

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.

Recent Developments

Acquisition of Metromedia Gas & Power, Inc.

On October 1, 2014, we completed the purchase of Metromedia Gas & Power Inc’s (“Metromedia Energy”) natural gas marketing and electricity brokerage business for $22.0 million, not including the purchase of natural gas inventory, utility security deposits, and other adjustments. Total consideration at closing was $32.8 million. Metromedia Energy markets natural gas and brokers electricity to commercial, industrial and municipal consumers in the Northeast and Mid-Atlantic, providing customers with approximately 15 Bcf of natural gas and assisting in the procurement of approximately 150 Megawatts of power demand annually. Metromedia Energy’s natural gas portfolio includes more than 8,500 accounts who are served by over thirty utilities from twelve interstate pipeline connections between Virginia and Maine and as far west as Ohio. Metromedia provides electricity brokerage services for more than 7,000 commercial and industrial accounts behind forty-six utilities across seventeen states and Washington D.C.

The acquisition was accounted for as a business combination and was financed with borrowings under our credit facility. The allocation of the purchase price to the assets acquired and liabilities assumed will be finalized as we receive additional information regarding the acquisition, including a final valuation of the assets purchased.

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, 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:

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

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The ability of our assets to generate cash sufficient to pay interest on our indebtedness and make distributions to our equity holders; and

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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

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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. 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, over the three year period ended September 30, 2014 NYMEX heating oil (HO) contracts have ranged from a high of $3.32 per gallon to a low of $2.53 per gallon. 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 September 30, 2014, we hedged approximately 39% 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, 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 October 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 September 30, 2013		Nine Months Ended September 30, 2013
	(unaudited)
	($ in thousands)
Net sales	$	194,146	$	455,731
Gross margin	$	9,217	$	18,551
Adjusted gross margin	$	9,217	$	18,551

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 nine months ended September 30, 2014 and 2013.


	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
				Predecessor						Predecessor
	(in thousands)						(in thousands)
Volumes:
Refined products (gallons)		231,126			308,135			1,039,584			1,073,167
Natural gas (MMBtus)		10,275			9,983			38,264			38,312
Materials handling (short tons)		741			538			1,960			1,616
Materials handling (gallons)		55,440			54,474			167,622			177,030
Other operations (short tons)		11			34			76			105
Net Sales:
Refined products	$	666,538		$	879,691		$	3,187,482		$	3,148,743
Natural gas		53,376			49,623			255,058			222,704
Materials handling		7,739			7,185			24,140			21,713
Other operations		1,168			3,776			8,305			13,888

Total net sales	$	728,821		$	940,275		$	3,474,985		$	3,407,048

Gross Margin:
Refined products	$	23,547		$	26,119		$	89,003		$	82,902
Natural gas		(11,203	)		(8,599	)		49,185			16,639
Materials handling		7,765			7,181			24,158			21,700
Other operations		222			1,000			790			3,369

Total gross margin	$	20,331		$	25,701		$	163,136		$	124,610

Adjusted Gross Margin:
Refined products	$	21,656		$	25,447		$	81,092		$	78,593
Natural gas		4,604			4,415			42,614			28,401
Materials handling		7,765			7,181			24,158			21,700
Other operations		222			1,000			790			3,369

Total adjusted gross margin	$	34,247		$	38,043		$	148,654		$	132,063

Calculation of Adjusted Gross Margin:
Total gross margin	$	20,331		$	25,701		$	163,136		$	124,610
Deduct: total commodity derivative (gains) losses included in net income (loss)(1)		(18,967	)		23,051			(6,150	)		21,200
Add: realized commodity derivative gains (losses) included in net income (loss)(1)		32,883			(10,709	)		(8,332	)		(13,747	)

Total adjusted gross margin (2)	$	34,247		$	38,043		$	148,654		$	132,063


	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
				Predecessor						Predecessor
	(in thousands)						(in thousands)
Reconciliation to Net Income:
Gross margin	$	20,331		$	25,701		$	163,136		$	124,610
Operating costs and expenses not allocated to operating segments:
Operating expenses		11,626			12,844			37,504			40,444
Selling, general and administrative		13,277			12,633			48,670			39,689
Depreciation and amortization		2,383			4,034			7,070			12,471

Total operating costs and expenses		27,286			29,511			93,244			92,604

Operating income		(6,955	)		(3,810	)		69,892			32,006
Other (expense) income		—			(215	)		—			601
Interest income		122			261			388			521
Interest expense		(4,241	)		(7,207	)		(13,930	)		(21,846	)
Income tax provision		356			4,560			(1,227	)		(6,078	)

Net income	$	(10,718	)	$	(6,411	)	$	55,123		$	5,204

Reconciliation of EBITDA to Net Income:
Net income	$	(10,718	)	$	(6,411	)	$	55,123		$	5,204
Add/(deduct):
Interest expense, net		4,119			6,946			13,542			21,325
Tax (benefit) expense		(356	)		(4,560	)		1,227			6,078
Depreciation and amortization		2,383			4,034			7,070			12,471

EBITDA (2):	$	(4,572	)	$	9		$	76,962		$	45,078

Deduct: total commodity derivative (gains) losses included in net income (loss)(1)		(18,967	)		23,051			(6,150	)		21,200
Add: realized commodity derivative gains (losses) included in net income (loss)(1)		32,883			(10,709	)		(8,332	)		(13,747	)
Add/(deduct): Bio-fuel excise tax credits (3)		—			—			—			(5,021	)

Adjusted EBITDA (2):	$	9,344		$	12,351		$	62,480		$	47,510

Other Data:
Normal heating degree days(4)		204			204			4,432			4,432
Actual heating degree days		201			211			4,742			4,288
Variance from normal heating degree days		(1.5	)%		3.4	%		7.0	%		(3.2	)%
Variance from prior period actual heating degree days		(4.7	)%		29.4	%		10.6	%		15.9	%

(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 nine months ended September 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 September 30, 2014 compared to Three Months Ended September 30, 2013

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


	Three Months Ended September 30,						Increase/(Decrease)
	2014			2013			$			%
				Predecessor
	($ in thousands, except unit gross margin and adjusted unit gross margin)
Volumes:
Refined products (gallons)		231,126			308,135			(77,009	)		(25	)%
Natural gas (MMBtus)		10,275			9,983			292			3	%
Materials handling (short tons)		741			538			203			38	%
Materials handling (gallons)		55,440			54,474			966			2	%
Other operations (short tons)		11			34			(23	)		(68	)%
Net Sales:
Refined products	$	666,538		$	879,691		$	(213,153	)		(24	)%
Natural gas		53,376			49,623			3,753			8	%
Materials handling		7,739			7,185			554			8	%
Other operations		1,168			3,776			(2,608	)		(69	)%

Total net sales	$	728,821		$	940,275		$	(211,454	)		(22	)%

Gross Margin:
Refined products	$	23,547		$	26,119		$	(2,572	)		(10	)%
Natural gas		(11,203	)		(8,599	)		(2,604	)		30	%
Materials handling		7,765			7,181			584			8	%
Other operations		222			1,000			(778	)		(78	)%

Total gross margin	$	20,331		$	25,701		$	(5,370	)		(21	)%

Unit Gross Margin:
Refined products	$	0.102		$	0.085		$	0.017			20	%
Natural gas	$	(1.090	)	$	(0.861	)	$	(0.229	)		27	%
Adjusted Gross Margin:
Refined products	$	21,656		$	25,447		$	(3,791	)		(15	)%
Natural gas		4,604			4,415			189			4	%
Materials handling		7,765			7,181			584			8	%
Other operations		222			1,000			(778	)		(78	)%

Total adjusted gross margin	$	34,247		$	38,043		$	(3,796	)		(10	)%

Adjusted Unit Gross Margin:
Refined products	$	0.094		$	0.083		$	0.011			13	%
Natural gas	$	0.448		$	0.442		$	0.006			1	%

Refined Products

Refined products net sales were $666.5 million and $879.7 million for the three months ended September 30, 2014 and 2013, respectively. Excluding Kildair’s net sales of $191.5 million for the three months ended September 30, 2013, refined products net sales decreased $21.7 million, or 3%, which was driven by lower prices. Excluding Kildair’s sales volumes of 80.8 million gallons for the three months ended September 30, 2013, refined products sales volumes were 231.1 million gallons and 227.3 million gallons for the three months ended September 30, 2014 and 2013, respectively. Distillate sales volumes increased 21.5 million gallons, or 15%, period over period, with a significant increase in diesel sales more than offsetting a modest reduction in heating oil. The increase in diesel volumes was driven by contracts acquired from Hess Corporation at the end of 2013. The lower heating oil volumes were primarily driven by our July 1, 2014 transition to the higher cost, low sulfur (500 ppm) heating oil specification product now used in certain key states (Massachusetts, Rhode Island, and Connecticut) where we operate.

Gasoline sales volumes decreased by approximately 14.2 million gallons, or 19%, for the three months ended September 30, 2014 as compared to the same period in 2013 due to a combination of a highly competitive pricing environment and backwardation losses that pushed wholesale margins below our minimum thresholds. Residual fuel oil sales volumes decreased 3.5 million gallons, or 25%, for the three months ended September 30, 2014 as compared to the same period in 2013, as a result of lower spot sales to utilities. The average selling price per gallon was approximately 5% lower for the three months ended September 30, 2014 as compared to the same period in 2013.

Excluding Kildair’s gross margin and adjusted gross margin of $8.5 million for the three months ended September 30, 2013, refined products gross margin was $23.5 million and $17.6 million for the three months ended September 30, 2014 and 2013, respectively. Refined products adjusted gross margin, exclusive of Kildair, was $21.7 million and $16.9 million for the three months ended September 30, 2014 and 2013, respectively. For the three months ended September 30, 2014 and 2013, refined products adjusted gross margin was $1.8 million lower and $0.7 million lower, 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 increase of $4.8 million, or 28%, was primarily attributable to increases in distillates, notably increased diesel sales associated with the assumption of the Hess Corporation contracts.

Natural Gas

Natural gas net sales were $53.4 million and $49.6 million for the three months ended September 30, 2014 and 2013, respectively. The natural gas net sales increase of $3.8 million, or 8%, was driven by higher commodity prices as the average natural gas price per MMBtu was approximately 5% higher during the three months ended September 30, 2014 as compared to the same period in 2013. Natural gas sales volumes increased approximately 3% for the three months ended September 30, 2014 as compared to the same period in 2013.

Natural gas gross margin was $(11.2) million and $(8.6) million for the three months ended September 30, 2014 and 2013, respectively. Natural gas adjusted gross margin was $4.6 million and $4.4 million for the three months ended September 30, 2014 and 2013, respectively. Natural gas adjusted gross margin was $15.8 million higher than natural gas gross margin for the three months ended September 30, 2014 and $13.0 million higher than natural gas gross margin for the three months ended September 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 increased $0.2 million, or 4%, with volumes and unit margins remaining relatively unchanged from the prior period.

Materials Handling

Materials handling net sales were $7.7 million and $7.2 million for the three months ended September 30, 2014 and 2013, respectively. The materials handling net sales increase of $0.5 million, or 8%, was primarily due to increased dry bulk requirements during the quarter.

The materials handling gross margin increase of $0.6 million, or 8%, was primarily a result of an increase in dry bulk activity, in particular furnace slag and gypsum, with part of the increase due to vessel timing differences. The margins in the other key materials handling categories (liquid bulk and break bulk) were comparable for the two periods.

Other Operations

Net sales from our other operations were $1.2 million and $3.8 million for the three months ended September 30, 2014 and 2013, respectively, representing a decrease of $2.6 million. Excluding net sales of $2.6 million from Kildair’s commercial trucking activities for the three months ended September 30, 2013, other operations revenue remained unchanged.

Gross margins from our other operations were $0.2 million and $1.0 million for the three months ended September 30, 2014 and 2013, respectively, representing a decrease of $0.8 million. Excluding gross margin of $0.7 million from Kildair’s commercial trucking activities for the three months ended September 30, 2013, gross margin decreased $0.1 million.

Nine Months Ended September 30, 2014 compared to Nine Months Ended September 30, 2013

Our results of operations for the nine months ended September 30, 2014 reflect decreasing sales volumes and increasing 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 nine months ended September 30, 2014 reflects increasing adjusted unit gross margin for refined products and increasing adjusted unit gross margin for natural gas.


	Nine Months Ended September 30,				Increase/(Decrease)
	2014		2013		$			%
			Predecessor
	($ in thousands, except unit gross margin and adjusted unit gross margin)
Volumes:
Refined products (gallons)		1,039,584		1,073,167		(33,583	)		(3	)%
Natural gas (MMBtus)		38,264		38,312		(48	)		0	%
Materials handling (short tons)		1,960		1,616		344			21	%
Materials handling (gallons)		167,622		177,030		(9,408	)		(5	)%
Other operations (short tons)		76		105		(29	)		(28	)%
Net Sales:
Refined products	$	3,187,482	$	3,148,743	$	38,739			1	%
Natural gas		255,058		222,704		32,354			15	%
Materials handling		24,140		21,713		2,427			11	%
Other operations		8,305		13,888		(5,583	)		(40	)%

Total net sales	$	3,474,985	$	3,407,048	$	67,937			2	%

Gross Margin:
Refined products	$	89,003	$	82,902	$	6,101			7	%
Natural gas		49,185		16,639		32,546			196	%
Materials handling		24,158		21,700		2,458			11	%
Other operations		790		3,369		(2,579	)		(77	)%

Total gross margin	$	163,136	$	124,610	$	38,526			31	%

Unit Gross Margin:
Refined products	$	0.086	$	0.077	$	0.009			12	%
Natural gas	$	1.285	$	0.434	$	0.851			196	%
Adjusted Gross Margin:
Refined products	$	81,092	$	78,593	$	2,499			3	%
Natural gas		42,614		28,401		14,213			50	%
Materials handling		24,158		21,700		2,458			11	%
Other operations		790		3,369		(2,579	)		(77	)%

Total adjusted gross margin	$	148,654	$	132,063	$	16,591			13	%

Adjusted Unit Gross Margin:
Refined products	$	0.078	$	0.073	$	0.005			7	%
Natural gas	$	1.114	$	0.741	$	0.373			50	%

Refined Products

Refined products net sales were $3.2 billion and $3.1 billion for the nine months ended September 30, 2014 and 2013, respectively. Excluding Kildair’s net sales of $447.8 million for the nine months ended September 30, 2013, the refined products net sales increased $486.6 million, or 18%, which was driven primarily by higher sales volumes. Excluding Kildair’s sales volumes of 190.5 million gallons for the nine months ended September 30, 2013, refined products sales volumes were 1.0 billion gallons and 882.7 million gallons for the nine months ended September 30, 2014 and 2013, respectively. Distillate sales volumes increased 165.9 million gallons, or 25%, 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 higher sales to power plant customers to meet 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, Connecticut terminal that was purchased in the second half of 2013.

Gasoline sales volumes decreased by approximately 25.7 million gallons, or 14%, for the nine months ended September 30, 2014 as compared to the same period in 2013. This decrease was primarily a result of a highly competitive pricing environment in our key markets. Residual fuel oil sales volumes increased 16.7 million gallons, or 33%, for the nine months ended September 30, 2014 as compared to the same period in 2013, with the volume increases 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 nine months ended September 30, 2014 as compared to the same period in 2013.

Excluding Kildair’s gross margin and adjusted gross margin of $16.5 million for the nine months ended September 30, 2013, refined products gross margin was $89.0 million and $66.5 million for the nine months ended September 30, 2014 and 2013, respectively. Refined products adjusted gross margin, exclusive of Kildair, was $81.1 million and $62.1 million for the nine months ended September 30, 2014 and 2013, respectively. For the nine months ended September 30, 2014 and 2013, refined products adjusted gross margin was $7.9 million and $4.4 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 increase in refined products adjusted gross margin increase of $19.0 million, or 30%, was improved returns in distillate fuels, with both heating oil and diesel fuel providing substantial increases. The increase in heating oil adjusted gross margin was due to a combination of higher volumes and unit margins. The improvement in diesel margin generation were nearly all due to higher volumes, including increases 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 both reduced compared to the previous year. Higher residual fuel sales volumes and improved unit margins led to the increase in adjusted gross margin for heavy fuel oil.

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 nine months ended September 30, 2013 includes a $5.0 million benefit. There was no comparable adjustment for the nine months ended September 30, 2014.

Natural Gas

Natural gas net sales were $255.1 million and $222.7 million for the nine months ended September 30, 2014 and 2013, respectively. The natural gas sales increase of $32.4 million, or 15%, was driven by higher commodity prices as the average natural gas price per MMBtu was approximately 15% higher during the nine months ended September 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 nine months of 2014, in particular during the first quarter. Natural gas sales volumes were flat for the nine months ended September 30, 2014 as compared to the same period in 2013.

Natural gas gross margin was $49.2 million and $16.6 million for the nine months ended September 30, 2014 and 2013, respectively. Natural gas adjusted gross margin was $42.6 million and $28.4 million for the nine months ended September 30, 2014 and 2013, respectively. Natural gas adjusted gross margin was $6.6 million lower than natural gas gross margin for the nine months ended September 30, 2014 and $11.8 million higher than natural gas gross margin for the nine months ended September 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 $14.2 million, or 50%, 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 $24.1 million and $21.7 million for the nine months ended September 30, 2014 and 2013, respectively. The materials handling net sales increase of $2.4 million, or 11%, was primarily due to higher dry bulk handling volumes. These increases were partially offset by decreased liquid bulk revenue, in particular for asphalt handling.

The materials handling gross margin increase of $2.5 million, or 11%, was primarily due to an increase in dry bulk handling volumes of salt and petroleum coke. This increase was driven by a combination of low activity in 2013 due to higher bulk product inventories as a result of warm weather (e.g. salt) and timing differences in deliveries. (i.e. a shipment in late 2013 rather than early 2014) The dry bulk product increases were partially offset by a liquid bulk reduction primarily driven by reduced asphalt margins as a cold inclement spring delayed the start of the 2014 paving season. The overall margin for break bulk activity was modestly higher than the comparable period in 2013, with higher paper activity offsetting reduced pulp requirements and a one-time option payment received in 2013.

Other Operations

Net sales from our other operations were $8.3 million and $13.9 million for the nine months ended September 30, 2014 and 2013, respectively, representing a decrease of $5.6 million. Excluding net sales of $7.9 million from Kildair’s commercial trucking activities for the nine months ended September 30, 2013, other revenue increased $2.3 million.

Gross margins from our other operations were $0.8 million and $3.4 million for the nine months ended September 30, 2014 and 2013, respectively, representing a decrease of $2.6 million. Excluding gross margin of $2.1 million from Kildair’s commercial trucking activities for the nine months ended September 30, 2013, gross margin decreased $0.5 million.

Operating Costs and Expenses

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


	Three Months Ended September 30,				Increase/(Decrease)
	2014		2013		$			%
	($ in thousands)
Operating expenses	$	11,626	$	12,844	$	(1,218	)	(9)%
Selling, general and administrative expenses	$	13,277	$	12,633	$	644		5%
Depreciation and amortization	$	2,383	$	4,034	$	(1,651	)	(41)%

Operating Expenses. Operating expenses for the three months ended September 30, 2014 decreased $1.2 million, or 9%, as compared to the three months ended September 30, 2013. Excluding Kildair’s operating expenses for the three months ended September 30, 2013 of $2.3 million, operating expenses increased $1.1 million or 11%. Of this increase $0.7 million was primarily due to increased dry bulk handling volumes and $0.5 million was due to terminal operating expenses related to our Bridgeport terminal which was acquired on July 31, 2013.

Selling, General and Administrative Expenses. Selling, general and administrative expenses for the three months ended September 30, 2014, increased $0.6 million, or 5%, as compared to the three months ended September 30, 2013. Excluding Kildair’s expenses for the three months ended September 30, 2013 of $1.2 million, selling, general and administrative expenses increased by $1.8 million or 16%. Of this increase $1.4 million was due to higher employee related expenses which were primarily attributed to increased incentive compensation and higher sales commissions from higher earnings performance and $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 September 30, 2014 decreased $1.7 million, or 41% as compared to the three months ended September 30, 2013. Of this decrease $1.5 million was due to Kildair’s depreciation expense in the three months ended September 30, 2013.

Nine Months Ended September 30, 2014 compared to Nine Months Ended September 30, 2013


	Nine Months Ended September 30,				Increase/(Decrease)
	2014		2013		$			%
	($ in thousands)
Operating expenses	$	37,504	$	40,444	$	(2,940	)	(7)%
Selling, general and administrative expenses	$	48,670	$	39,689	$	8,981		23%
Depreciation and amortization	$	7,070	$	12,471	$	(5,401	)	(43)%

Operating Expenses. Operating expenses for the nine months ended September 30, 2014 decreased $2.9 million, or 7%, as compared to the nine months ended September 30, 2013. Excluding Kildair’s operating expenses for the nine months ended September 30, 2013 of $7.9 million, operating expenses increased $5.0 million or 15%. Of this increase, $2.2 million was due to terminal operating expenses related to our Bridgeport terminal which was acquired on July 31, 2013, $1.8 million was due to increased dry bulk handling volumes, and $1.0 million was primarily due to increased maintenance, insurance and utility expenses.

Selling, General and Administrative Expenses. Selling, general and administrative expenses for the nine months ended September 30, 2014, increased $9.0 million, or 23%, as compared to the nine months ended September 30, 2013. Excluding Kildair’s expenses for the nine months ended September 30, 2013 of $3.8 million, selling, general and administrative expenses increased by $12.8 million or 35%. Of this increase $10.2 million was due to higher employee related expenses primarily attributed to increased incentive compensation and sales commissions as a result of higher earnings performance, $2.1 million related to increased professional fees associated with public company reporting and compliance requirements, and $0.5 million was primarily related to expenses associated with mergers and acquisition activities.

Depreciation and Amortization. Depreciation and amortization for the nine months ended September 30, 2014 decreased $5.4 million, or 43% as compared to the nine months ended September 30, 2013. Of this decrease $5.3 million was due to Kildair’s depreciation expense in the nine months ended September 30, 2013.

Interest Expense, net

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


	Three Months Ended September 30,				Increase/(Decrease)
	2014		2013		$			%
	($ in thousands)
Interest expense, net	$	4,119	$	6,946	$	(2,827	)	(41)%

Interest Expense, net. Interest expense, net for the three months ended September 30, 2014 decreased $2.8 million, or 41%, as compared to the three months ended September 30, 2013. Of this decrease, $1.2 million was related to Kildair’s interest expense and $1.6 million was primarily due to lower aggregate borrowings under our revolving credit facilities and lower interest rate derivative obligations.

Nine Months Ended September 30, 2014 compared to Nine Months Ended September 30, 2013


	Nine Months Ended September 30,				Increase/(Decrease)
	2014		2013		$			%
	($ in thousands)
Interest expense, net	$	13,542	$	21,325	$	(7,783	)	(36)%

Interest Expense, net. Interest expense, net for the nine months ended September 30, 2014 decreased $7.8 million, or 36%, as compared to the nine months ended September 30, 2013. Of this decrease, $2.9 million was related to Kildair’s interest expense and $4.9 million was primarily due to lower aggregate borrowings under our revolving credit facilities 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 September 30, 2014, the Partnership had working capital of approximately $161.8 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 September 30, 2014, the borrowing base under the Partnership’s working capital facility was approximately $481.5 million. As of September 30, 2014, working capital borrowings were $261.9 million and outstanding letters of credit were $45.6 million, providing us with approximately $174.0 million in undrawn borrowing capacity under the working capital facility.

As of September 30, 2014, the Partnership had $129.9 million in outstanding borrowings under our acquisition facility, resulting in $120.1 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 working capital 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 working capital debt is reduced. During the nine months ended September 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 September 30, 2014, Axel Johnson provided us with approximately $4.7 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 entered into in connection with the closing of the IPO, it was agreed to use 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, and pursuant to such omnibus agreement, Axel Johnson agreed to provide trade credit support, consistent with past practice, through December 31, 2016, if and to the extent such trade credit support is necessary. 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 business.

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

Credit Agreement

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 (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 the level 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 are 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 nine months ended September 30, 2014, we incurred a total of approximately $3.1 million in maintenance capital expenditures and we spent $0.5 million for expansion and/or upgrades of our terminals. We anticipate that future maintenance capital expenditures will be funded with our acquisition line and that future expansion capital requirements will be financed either through our acquisition line or other long-term borrowings and/or equity offerings.

Cash Flows


	Nine Months Ended September 30,
	2014			2013
	($ in thousands)
Net cash provided by operating activities	$	93,903		$	149,928
Net cash used in investing activities	$	(3,602	)	$	(35,739	)
Net cash used in financing activities	$	(90,914	)	$	(114,406	)

Operating Activities

Net cash provided by operating activities for the nine months ended September 30, 2014 was approximately $93.9 million. This was primarily driven by net income of $55.1 million, a decrease in accounts receivable of $84.1 million, a decrease in inventories of $78.4 million, and depreciation and amortization totaling $9.1 million. This was partially offset by a reduction in accounts payable and accrued liabilities of $67.8 million, a net increase in the fair value of commodity derivative instruments totaling $57.2 million, and an increase in prepaid expenses and other assets of $23.9 million. The decrease in inventory occurred as a result of both decreased volumes and declining refined fuel prices that occurred primarily during the three months ended September 30, 2014. The decreases in accounts receivable, accounts payable and accrued liabilities were due to the seasonal impact of the peak winter season of the Northeast United States. The increase in derivative instruments was due to recognizing natural gas fixed forwards during the period.

Net cash provided by operating activities for the nine months ended September 30, 2013 was approximately $149.9 million. Cash flow from operations was driven by a decrease of $144.2 million in inventory and $56.8 million in accounts receivable due to the seasonal impact of the peak winter season of the Northeast United States. Accounts payable and accrued liabilities decreased $61.7 million with lower inventory levels.

Investing Activities

Net cash used in investing activities for the nine months ended September 30, 2014 was approximately $3.6 million and consisted primarily of capital expenditure projects across our terminal system.

Net cash used in investing activities for the nine months ended September 30, 2013 was approximately $35.7 million of which $20.7 million related to the purchase of the Bridgeport terminal, $11.5 million related to expansion capital expenditure projects at the Kildair terminal for a crude oil storage and handling construction project. The remaining $5.6 million primarily relates to numerous other capital projects across our terminal system, partially offset by the receipt of $1.9 million from insurance proceeds.

Financing Activities

Net cash used in financing activities for the nine months ended September 30, 2014 was approximately $90.9 million. Reduced financing requirements from lower inventory and accounts receivable resulted in $67.7 million less in net borrowings under our revolving credit facility. Distributions to unitholders were $22.7 million.

Net cash used in financing activities for the nine months ended September 30, 2013 was approximately $114.4 million and primarily resulted from $82.6 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 dividends of $40.0 million 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 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 nine months ended September 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 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.

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 nine months ended September 30, 2014 and 2013:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
				Predecessor						Predecessor
Refined products contracts	$	30,197		$	(9,142	)	$	40,194		$	2,921
Natural gas contracts		(11,230	)		(13,909	)		(34,044	)		(24,121	)

Total	$	18,967		$	(23,051	)	$	6,150		$	(21,200	)

Substantially all of our commodity derivative contracts outstanding as of September 30, 2014 will settle prior to March 31, 2016.

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 September 30, 2014, we held three interest rate swap agreements with a notional value of $100.0 million with swap periods that expire in January 2015; six interest rate swaps with a total notional value of $175.0 million whose swap periods begin in January 2015, expiring in January 2016; and five interest rate swaps with a total notional value of $150.0 million whose swap periods begin in January 2016, expiring in January 2017. 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 September 30, 2014, we hedged approximately 39% 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 as interest expense when payments are made. We expect to continue to utilize interest rate swaps to manage our exposure to LIBOR interest to earnings 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 September 30, 2014:


	As of September 30, 2014
	Fair Value Measurement		Quoted Prices in Active Markets Level 1		Significant Other Observable Inputs Level 2		Significant Unobservable Inputs Level 3
Financial assets:
Commodity exchange contracts	$	119	$	119	$	—	$	—
Commodity fixed forwards		96,389		—		96,389		—
Commodity swaps and options		106		—		106		—

Commodity derivatives		96,614		119		96,495		—
Interest rate swaps		116		—		116		—

Total	$	96,730	$	119	$	96,611	$	—

Financial liabilities:
Commodity exchange contracts	$	—	$	—	$	—	$	—
Commodity fixed forwards		102,789		—		102,789		—
Commodity swaps and options		106		—		106		—

Commodity derivatives		102,895		—		102,895		—
Interest rate swaps		694		—		694		—

Total	$	103,589	$	—	$	103,589	$	—

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 September 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 September 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 nine months ended September 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

(c)

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).



2.1	—	Asset Purchase Agreement, dated September 10, 2014, by and among Sprague Operating Resources LLC, Metromedia Gas & Power, Inc., Metromedia Gas LLC, Metromedia Energy, Inc., EnergyEXPRESS, Inc. and Metromedia Power, Inc. (incorporated by reference to Exhibit 2.1 of Sprague Resources LP’s Current Report on Form 8-K filed September 11, 2014).

3.1	—	First Amended and Restated Agreement of Limited Partnership of Sprague Resources LP (incorporated by reference to Exhibit 3.1 of Sprague Resources LP’s Current Report on Form 8-K filed November 5, 2013).

3.2	—	First Amended and Restated Limited Liability Company Agreement of Sprague Resources GP LLC (incorporated by reference to Exhibit 3.2 of Sprague Resources LP’s Current Report on Form 8-K filed November 5, 2013).

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.

SIGNATURES

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


	SPRAGUE RESOURCES LP

	By:	Sprague Resources GP LLC,
		Its General Partner

Date: November 12, 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.



2.1	—	Asset Purchase Agreement, dated September 10, 2014, by and among Sprague Operating Resources LLC, Metromedia Gas & Power, Inc., Metromedia Gas LLC, Metromedia Energy, Inc., EnergyEXPRESS, Inc. and Metromedia Power, Inc. (incorporated by reference to Exhibit 2.1 of Sprague Resources LP’s Current Report on Form 8-K filed September 11, 2014).

3.1	—	First Amended and Restated Agreement of Limited Partnership of Sprague Resources LP (incorporated by reference to Exhibit 3.1 of Sprague Resources LP’s Current Report on Form 8-K filed November 5, 2013).

3.2	—	First Amended and Restated Limited Liability Company Agreement of Sprague Resources GP LLC (incorporated by reference to Exhibit 3.2 of Sprague Resources LP’s Current Report on Form 8-K filed November 5, 2013).

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