Edgar Filing: Sprague Resources LP

Large accelerated filer

Accelerated filer

Non-accelerated filer

¨ (Do not check if a smaller reporting company)

Smaller reporting company

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2015

¨	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 11,004,292 common units and 10,071,970 subordinated units outstanding as of May 4, 2015

Table of Contents


		Page

PART I—FINANCIAL INFORMATION

Item 1.	Financial Statements:
	Condensed Consolidated Balance Sheets as of March 31, 2015 and December 31, 2014		3
	Unaudited Condensed Consolidated Statements of Operations for the three months ended March 31, 2015 and March 31, 2014		4
	Unaudited Condensed Consolidated Statements of Comprehensive Income for the three months ended March 31, 2015 and March 31, 2014		5
	Unaudited Condensed Consolidated Statement of Unitholders’ Equity(Deficit) for the three months ended March 31, 2015		6
	Unaudited Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2015 and March 31, 2014		7
	Notes to Unaudited Condensed Consolidated Financial Statements		8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		25
Item 3.	Quantitative and Qualitative Disclosures about Market Risk		42
Item 4.	Controls and Procedures		44

PART II—OTHER INFORMATION

Item 1.	Legal Proceedings		45
Item 1A.	Risk Factors		45
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		45
Item 3.	Defaults Upon Senior Securities		45
Item 4.	Mine Safety Disclosures		45
Item 5.	Other Information		45
Item 6.	Exhibits		46
Signatures			47

Part I – FINANCIAL INFORMATION

Item 1 – Financial Statements

Sprague Resources LP

Condensed Consolidated Balance Sheets

(in thousands except units)


	March 31, 2015			December 31, 2014
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	21,609		$	4,080
Accounts receivable, net		342,174			289,424
Inventories		217,912			390,555
Fair value of derivative assets		169,298			229,890
Deferred income taxes		961			895
Other current assets		50,115			52,416

Total current assets		802,069			967,260
Property, plant, and equipment, net		251,336			250,126
Assets held for sale		68			1,321
Intangibles, net		25,585			27,626
Other assets, net		26,322			30,219
Goodwill		63,288			63,288

Total assets	$	1,168,668		$	1,339,840


Liabilities and unitholders’ equity
Current liabilities:
Accounts payable	$	124,972		$	198,609
Accrued liabilities		56,510			63,816
Fair value of derivative liabilities		55,685			89,176
Due to General Partner and affiliates		11,969			15,340
Current portion of long-term debt		258,678			397,214
Current portion of capital leases		1,004			1,313

Total current liabilities		508,818			765,468

Commitments and contingencies (Note 9)		—			—
Long-term debt		469,708			418,356
Long-term capital leases		4,245			5,424
Other liabilities		18,157			17,884
Due to General Partner		848			988
Deferred income taxes		15,190			15,826

Total liabilities		1,016,966			1,223,946

Unitholders’ equity:
Common unitholders - public (8,969,914 units and 8,777,922 units issued and outstanding, as of March 31, 2015 and December 31, 2014, respectively)		186,997			171,055
Common unitholders - affiliated (2,034,378 units issued and outstanding, as of March 31, 2015 and December 31, 2014, respectively)		(1,908	)		(5,566	)
Subordinated unitholders - affiliated (10,071,970 units issued and outstanding)		(21,652	)		(39,762	)
Accumulated other comprehensive loss, net of tax		(11,735	)		(9,833	)

Total unitholders’ equity		151,702			115,894

Total liabilities and unitholders’ equity	$	1,168,668		$	1,339,840

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

Sprague Resources LP

Unaudited Condensed Consolidated Statements of Operations

(in thousands except unit and per unit amounts)


	Three Months Ended March 31,
	2015			2014
Net sales	$	1,598,358		$	1,994,699
Cost of products sold (exclusive of depreciation and amortization)		1,490,373			1,864,419
Operating expenses		18,883			16,838
Selling, general and administrative		32,381			27,411
Depreciation and amortization		4,992			3,955

Total operating costs and expenses		1,546,629			1,912 ,623

Operating income		51,729			82,076
Other income		514			—
Interest income		112			110
Interest expense		(7,766	)		(8,016	)

Income before income taxes		44,589			74,170
Income tax provision		(650	)		(1,038	)

Net income		43,939			73,132
Exclude loss attributable to Kildair (Note 1)		—			2,203

Limited partners’ interest in net income	$	43,939		$	75,335


Net income per limited partner unit:
Common - basic	$	2.10		$	3.74
Common - diluted	$	2.06		$	3.74
Subordinated - basic and diluted	$	2.10		$	3.74
Units used to compute net income per limited partner unit:
Common - basic		10,897,488			10,072,186
Common - diluted		11,064,510			10,073,176
Subordinated - basic and diluted		10,071,970			10,071,970

Distribution declared per common and subordinated units	$	0.4725		$	0.4125

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

Sprague Resources LP

Unaudited Condensed Consolidated Statements of Comprehensive Income

(in thousands)


	Three Months Ended March 31,
	2015			2014
Net income	$	43,939		$	73,132
Other comprehensive (loss) income, net of tax:
Unrealized (loss) gain on interest rate swaps
Net loss arising in the period		(700	)		(63	)
Reclassification adjustment related for losses realized in income		130			608

Net change in unrealized loss on interest rate swaps		(570	)		545
Tax effect		17			(14	)

		(553	)		531
Foreign currency translation adjustment		(1,349	)		(459	)

Other comprehensive (loss) income		(1,902	)		72

Comprehensive income	$	42,037		$	73,204

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

Sprague Resources LP

Unaudited Condensed Consolidated Statements of Unitholders’ Equity (Deficit)

(in thousands)


	Common- Public			Common- Sprague Holdings			Subordinated- Sprague Holdings			Accumulated Other Comprehensive (Loss) Income			Total
Balance at December 31, 2013	$	127,496		$	(6,155	)	$	(39,438	)	$	(10,610	)	$	71,293

Net income		50,141			9,953			62,720			—			122,814
Other comprehensive income		—			—			—			777			777
Unit-based compensation		1,528			286			1,803			—			3,617
Distribution to unitholders		(13,370	)		(2,460	)		(15,764	)		—			(31,594	)
Distribution to sponsor for Kildair acquisition		—			(17,652	)		(49,015	)		—			(66,667	)
Common units issued for Kildair acquisition		—			10,002			—			—			10,002
Common units issued for Castle acquisition		5,318			—			—			—			5,318
Other contribution from Parent		—			470			—			—			470
Repurchased units withheld for employee tax obligation		(58	)		(10	)		(68	)		—			(136	)

Balance at December 31, 2014		171,055			(5,566	)		(39,762	)		(9,833	)		115,894

Net income		18,571			4,263			21,105			—			43,939
Other comprehensive loss		—			—			—			(1,902	)		(1,902	)
Unit-based compensation		323			74			367			—			764
Distribution to unitholders		(4,050	)		(931	)		(4,608	)		—			(9,589	)
Common units issued in connection with annual bonus		2,088			479			2,372			—			4,939
Repurchased units withheld for employee tax obligation		(990	)		(227	)		(1,126	)		—			(2,343	)

Balance at March 31, 2015	$	186,997		$	(1,908	)	$	(21,652	)	$	(11,735	)	$	151,702

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

Sprague Resources LP

Unaudited Condensed Consolidated Statements of Cash Flows

(in thousands)


	Three Months Ended March 31,
	2015			2014
Cash flows from operating activities
Net income	$	43,939		$	73,132
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization (includes amortization of deferred debt issue costs)		5,898			5,179
Provision for doubtful accounts		730			190
Gain on sale of assets and insurance recoveries		(514	)		(5	)
Deferred income taxes		(678	)		620
Non-cash unit-based compensation		4,068			538
Changes in assets and liabilities:
Accounts receivable		(53,480	)		(59,883	)
Inventories		172,643			135,747
Prepaid expenses and other assets		7,230			424
Fair value of commodity derivative instruments		26,531			(52,750	)
Due to General Partner and affiliates		(3,510	)		12,928
Accounts payable, accrued liabilities and other		(80,439	)		(25,617	)

Net cash provided by operating activities		122,418			90,503

Cash flows from investing activities
Purchases of property, plant and equipment		(3,527	)		(5,600	)
Proceeds from property insurance settlement and sale of assets		336			25

Net cash used in investing activities		(3,191	)		(5,575	)

Cash flows from financing activities
Net payments under credit agreements		(87,042	)		(74,016	)
Payments on capital lease liabilities and term debt		(390	)		(208	)
Payments on long-term terminal obligations		(97	)		(167	)
Debt issue costs		(1,938	)		—
Distribution to unitholders		(9,589	)		(5,693	)
Foreign exchange on capital lease obligations		(157	)		(88	)
Repurchased units withheld for employee tax obligation		(2,343	)		(136	)
Net increase in payable to Parent		—			147

Net cash used in financing activities		(101,556	)		(80,161	)

Effect of exchange rate changes on cash balances held in foreign currencies		(142	)		34

Net change in cash and cash equivalents		17,529			4,801
Cash and cash equivalents, beginning of period		4,080			2,046

Cash and cash equivalents, end of period	$	21,609		$	6,847

Supplemental disclosure of cash flow information
Cash paid for interest	$	6,929		$	7,429
Cash paid for taxes	$	773		$	511

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

Sprague Resources LP

Notes to Unaudited Condensed Consolidated Financial Statements

(in thousands unless otherwise stated)

1. Description of Business and Summary of Significant Accounting Policies

Partnership Businesses

Sprague Resources LP (the “Partnership”) is a Delaware limited partnership formed on June 23, 2011 to engage in activities for which limited partnerships may be organized under the Delaware Revised Limited Partnership Act including, but not limited to, actions to form a limited liability company and/or acquire assets owned by Sprague Operating Resources LLC, a Delaware limited liability company and the Partnership’s operating company (the “Predecessor” and “OLLC”), an entity engaged in the sales and marketing of energy products, as well as materials handling operations.

Unless the context otherwise requires, references to “Sprague Resources,” and the “Partnership,” when used in a historical context prior to October 30, 2013, 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. 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.

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 19 refined products and materials handling terminals located in the Northeast United States and in Quebec, Canada. The Partnership also utilizes third-party terminals in the Northeast United States through which it sells or distributes refined products pursuant to rack, exchange and throughput agreements. The Partnership has four business segments: refined products, natural gas, materials handling and other operations. The refined products segment purchases a variety of refined products, such as heating oil, diesel fuel, residual fuel oil, kerosene, jet fuel, gasoline and asphalt (primarily from refining companies, trading organizations and producers), and sells them to wholesale and commercial customers. The natural gas segment purchases, sells and distributes natural gas to commercial and industrial customers in the Northeast and Mid-Atlantic United States. The Partnership purchases the natural gas it sells from natural gas producers and trading companies. The materials handling segment offloads, stores and prepares for delivery a variety of customer-owned products, including asphalt, clay slurry, salt, gypsum, crude oil, coal, petroleum coke, caustic soda, tallow, pulp and heavy equipment. The Partnership’s other operations include the purchase and distribution of coal and certain commercial trucking activities.

On October 1, 2012, the Predecessor acquired Kildair Service Ltd. and two related subsidiaries (together “Kildair”). Kildair owns a terminal in Sorel-Tracy, Quebec, on the St. Lawrence River where it maintains 3.3 million barrels of residual fuel, asphalt, and crude oil storage. Kildair’s primary businesses include marketing of residual fuel oil both locally and for export, marketing of asphalt including polymer modified grades, and crude-by-rail handling services. Kildair’s terminal has blending infrastructure allowing the ability to process a wide range of varying quality blend components.

In connection with the completion on October 30, 2013 of the initial public offering (the “IPO”) of common units representing limited partner interests in the Partnership, Axel Johnson Inc. 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, its ownership of 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.

On December 9, 2014, the Partnership acquired all of the equity interest in Kildair through the acquisition of the equity interests of Kildair’s parent, Sprague Canadian Properties, LLC, from a wholly owned subsidiary of Sprague Holdings. As this transaction represents a transfer of entities under common control, the Condensed Consolidated Financial Statements and related information presented herein have been recast to include the historical results of Kildair for all periods presented where Kildair was controlled by Axel Johnson, which commenced on October 1, 2012. Limited partners’ interest in net income as well as the related per unit amounts have not been recast for the three months ended March 31, 2014.

As of March 31, 2015, the Parent, through its ownership of Sprague Holdings owns 2,034,378 common units and 10,071,970 subordinated units, representing an aggregate 57% 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. 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.

Basis of Presentation

The Condensed Consolidated Financial Statements include the accounts of the Partnership and its wholly-owned subsidiaries. Intercompany transactions between the Partnership, and its subsidiaries have been eliminated. The accompanying unaudited condensed consolidated financial statements were prepared in accordance with the requirements of the Securities and Exchange Commission (“SEC”) for interim financial information. As permitted under those rules, certain notes or other financial information that are normally required by U.S. generally accepted accounting principles (“GAAP”) to be included in annual financial statements have been condensed or omitted from these interim financial statements. These interim financial statements should be read in conjunction with the consolidated financial statements and related notes of the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2014 as filed with the SEC on March 16, 2015 (the “2014 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 2014 Annual Report, and are the same as are used in preparing these unaudited interim condensed 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 and income taxes.

New Accounting Guidance

In April 2015, the Financial Accounting Standards Board issued Accounting Standard Update 2015-06, Earnings Per Share (Topic 260): Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions (a consensus of the Emerging Issues Task Force). The Partnership is currently evaluating the potential impact of this guidance, however at this time we do not believe that the application of this ASU will result in changes to the Partnership’s presentation of earnings per unit or related disclosures in connection with the Partnership’s 2014 dropdown transaction. This guidance is effective for fiscal years beginning after December 15, 2015 and interim periods within those fiscal years and is to be applied on a retrospective basis.

In April 2015, the Financial Accounting Standards Board issued Accounting Standard Update 2015-03, Simplifying the Presentation of Debt Issuance Costs, which requires debt issuance costs to be presented in the balance sheet as a direct deduction from the carrying value of the associated debt liability, consistent with the presentation of a debt discount. The Partnership has not yet adopted the provisions of this guidance which is effective for annual reporting periods beginning after December 15, 2015, and interim periods within those fiscal years. As of March 31, 2015 and December 31, 2014, the Partnership’s unamortized debt issuance costs were $16.9 million and $15.5 million respectively.

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, 2017, including interim periods within that reporting period.

2. Business Combinations

Acquisition of Kildair

On December 9, 2014, the Partnership indirectly acquired all of the equity interests in Kildair through the Partnership’s acquisition of all of the equity interest of Kildair’s parent, Sprague Canadian Properties LLC, from Axel Johnson for total consideration of $175.0 million, (a portion of which was used to retire Kildair debt) which included $10.0 million in the Partnership’s unregistered common units. As the acquisition of Kildair by the Partnership represents a transfer of entities under common control, the Condensed Consolidated Financial Statements and related information presented herein have been recast by including the historical financial results of Kildair for all periods that were controlled by Axel Johnson. As such, summarized financial information has not been presented. The Partnership recognized $1.7 million of acquisition-related costs that were expensed in 2014.

Acquisition of Castle Oil

On December 8, 2014, the Partnership acquired substantially all of the assets of Castle Oil Corporation (“Castle”) and certain of its affiliates by purchasing Castle’s Bronx, New York terminal and its associated wholesale, commercial, and retail fuel distribution business. The acquisition-date fair value of the consideration consisted of cash of $45.3 million, an obligation to pay $5.0 million over a three year period (net present value of $4.6 million) and $5.3 million in the Partnership’s unregistered common units, plus payments for Castle’s inventory and other current assets of $37.0 million. Castle’s Bronx terminal is a large deep water petroleum products terminal located in New York City, and has 0.9 million barrels of storage capacity. The purchase of this facility augments the Partnership’s supply, storage and marketing opportunities and provides new opportunities in refined fuels, and expanded materials handling capabilities. The acquisition was accounted for as a business combination and was financed with borrowings under the Partnership’s credit facility.

The following summarizes the preliminary fair values of the assets acquired and liabilities assumed:


Inventories	$	36,512
Derivative assets		4,837
Other current assets and prepaids		533
Property, plant and equipment		49,879
Intangibles and other assets		5,046

Total identifiable assets acquired		96,807
Accrued liabilities		2,018
Derivative liabilities		390
Long term capital leases		1,481
Other liabilities		761

Total liabilities assumed		4,650

Net assets acquired	$	92,157

A preliminary allocation of the purchase price to the assets acquired and liabilities assumed was made based on available information and incorporating management’s best estimates. The Partnership is currently in the process of finalizing the valuation of the assets acquired and liabilities assumed. The actual allocation of the final purchase price and resulting effect on income from operations may differ from the amounts included above. The Partnership expects to finalize the purchase allocation during 2015.

The following represents the unaudited pro forma consolidated net sales and net income as if Castle had been included in the unaudited consolidated results of the Partnership for the three months ended March 31, 2014.


	Three Months Ended March 31, 2014
Net sales	$	2,435,524
Net income	$	83,039
Limited partners’ interest in net income	$	85,242
Net income per limited partner common unit - basic	$	4.18
Net income per limited partner common unit - diluted	$	4.18

These amounts have been calculated after applying the Partnership’s accounting policies and adjusting the results of Castle to reflect the additional depreciation and amortization that would have been charged assuming the fair value adjustments to property, plant and equipment; and intangible assets had been applied on January 1, 2014, together with the consequential tax effects. The Partnership recognized $1.1 million of acquisition related costs that were expensed in 2014.

Acquisition of Metromedia Gas & Power, Inc.

On October 1, 2014, the Partnership completed its purchase of Metromedia Gas & Power Inc. (“Metromedia Energy”) 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 primarily in the Northeast and Mid-Atlantic United States. The acquisition was accounted for as a business combination and was financed with borrowings under the Partnership’s credit facility.

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


Inventories	$	1,365
Derivative assets		24,971
Other current assets		543
Intangible assets		13,900
Natural gas transportation assets		39,427
Other long term assets		6,683
Property, plant and equipment		556

Total identifiable assets acquired		87,445
Derivative liabilities		67,413
Other current liabilities		52
Natural gas transportation liabilities		1,458

Total liabilities assumed		68,923

Net identifiable assets acquired		18,522
Goodwill		14,243

Net assets acquired	$	32,765

The Partnership determined the fair value of intangible assets using income approaches that incorporated projected cash flows as well as excess earnings and lost profits methods. The Partnership determined the fair value of derivative assets, derivative liabilities and natural gas transportation assets by applying the Partnership’s existing valuation methodologies. The Partnership determined that book value approximated fair value for substantially all other assets and liabilities.

The goodwill recognized is primarily attributable to Metromedia Energy’s assembled workforce, its reputation in the Northeast United States and the residual cash flow the Partnership believes that it will be able to generate. The goodwill is expected to be deductible for tax purposes. The Partnership recognized $0.1 million of acquisition related costs that were expensed in 2014.

3. Accumulated Other Comprehensive Loss, Net of Tax

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


	March 31,			December 31,
	2015			2014
Fair value of interest rate swaps, net of tax	$	(959	)	$	(406	)
Cumulative foreign currency translation adjustment		(10,776	)		(9,427	)

Accumulated other comprehensive loss, net of tax	$	(11,735	)	$	(9,833	)

A summary of the changes in accumulated other comprehensive loss related to foreign currency translation is as follows:


	Three Months Ended March 31,
	2015			2014
Balance - beginning of period	$	(9,427	)	$	(8,284	)
Foreign currency translation adjustment		(1,349	)		(459	)

Balance - end of period	$	(10,776	)	$	(8,743	)

4. Inventories


	March 31,		December 31,
	2015		2014
Petroleum and related products	$	196,764	$	366,431
Asphalt		18,595		18,357
Coal		1,907		2,380
Natural gas		646		3,387

Inventories	$	217,912	$	390,555

Due to changing market conditions, the Partnership recorded a provision of $9.6 million and $50.5 million as of March 31, 2015 and December 31, 2014, respectively, to write-down petroleum, natural gas and asphalt inventory to its net realizable value. These charges are included in cost of products sold (exclusive of depreciation and amortization) in the Consolidated Statements of Operations.

5. Debt


	March 31,		December 31,
	2015		2014
Current debt
Credit agreement	$	258,460	$	396,961
Other		218		253

Current debt		258,678		397,214

Long-term debt
Credit agreement		469,240		417,789
Other		468		567

Long-term debt		469,708		418,356

Total debt	$	728,386	$	815,570

Credit Agreement

On December 9, 2014, in connection with the acquisition of Kildair, the Partnership entered into an amended and restated revolving credit agreement (the “Credit Agreement”) that will mature on December 9, 2019. The revolving credit facilities under the Credit Agreement contain, among other items, the following:

•

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

•

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

•

Revolving acquisition facility of up to $400.0 million to be used for loans and letters of credit to fund capital expenditures and acquisitions and other general corporate purposes related to the Partnership’s current businesses; and,

•

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

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

Indebtedness under the Credit Agreement will bear interest, at the Partnership’s option, at a rate per annum equal to either the Eurocurrency Base Rate (which is the LIBOR Rate for loans denominated in U.S. dollars and CDOR for loans denominated in Canadian dollars, in each case adjusted for certain regulatory costs) for interest periods of one, two, three or six months plus a specified margin or an alternate rate plus a specified margin.

For the U.S. dollar working capital facility and the acquisition facility, the alternate rate is the Base Rate which is the higher of (a) the U.S. Prime Rate as in effect from time to time, (b) the Federal Funds rate as in effect from time to time plus 0.50% and (c) the one-month Eurocurrency Rate for U.S. dollars as in effect from time to time plus 1.00%.

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

As of March 31, 2015 and December 31, 2014, working capital facilities borrowings were $416.1 million and $503.2 million, respectively, and outstanding letters of credit were $36.1 million and $120.2 million, respectively. The working capital facilities are subject to borrowing base reporting and as of March 31, 2015 and December 31, 2014, had a borrowing base of $639.1 million and $843.3 million, respectively. As of March 31, 2015, excess availability under the working capital facility was $186.9 million.

Acquisition line borrowings were $311.6 million at both March 31, 2015 and December 31, 2014, respectively. As of March 31, 2015, excess availability under the acquisition facility was $88.4 million.

The weighted average interest rate was 2.8% at both March 31, 2015 and December 31, 2014 respectively. The current portion of the credit agreement at March 31, 2015 and December 31, 2014 represents the amounts intended to be repaid during the following twelve month period.

The Credit Agreement contains certain restrictions and covenants among which are a minimum level of net working capital, fixed charge coverage and debt leverage ratios and limitations on the incurrence of indebtedness. As of March 31, 2015, the Partnership is in compliance with these financial covenants. The Credit Agreement limits the Partnership’s ability to make distributions in the event of a default as defined in the Credit Agreement.

6. Related Party Transactions

The General Partner charges the Partnership for the reimbursements of employee costs and related employee benefits and other overhead costs supporting the Partnership’s operations which amounted to $32.6 million and $30.1 million for the three months ended March 31, 2015 and 2014, respectively. 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 $12.8 million and $16.3 million as of March 31, 2015 and December 31, 2014 respectively.

7. 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 CFO/COO) to make key operating decisions and assess performance. These segments are refined products, natural gas, materials handling and other activities.

The Partnership’s refined products segment purchases a variety of refined products, such as heating oil, diesel fuel, residual fuel oil, asphalt, kerosene, jet fuel and gasoline (primarily from refining companies, trading organizations and producers), and sells them to its customers. The Partnership has wholesale customers who resell the refined products they purchase from the Partnership and commercial customers who consume the refined products they purchase 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, real estate management companies, hospitals and educational institutions.

The Partnership’s natural gas segment purchases, sells and distributes natural gas to commercial and industrial customers primarily in the Northeast and Mid-Atlantic United 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, crude oil, coal, petroleum coke, caustic soda, tallow, pulp and heavy equipment. These services are fee-based activities which are generally conducted under multi-year agreements.

The Partnership’s other activities include the purchase, sale and distribution of coal 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 net sales less cost of products sold (exclusive of depreciation and amortization) increased by unrealized hedging losses and decreased by unrealized hedging gains, in each case with respect to refined products and natural gas inventory and natural gas transportation contracts.

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

Summarized financial information for the Partnership’s reportable segments for the three months ended March 31, 2015 and 2014 is presented in the table below:


	Three Months Ended March 31,
	2015			2014
	(in thousands)
Net sales:
Refined products	$	1,431,845		$	1,844,973
Natural gas		146,679			134,340
Materials handling		10,184			8,079
Other operations		9,650			7,307

Net sales	$	1,598,358		$	1,994,699

Adjusted gross margin(1):
Refined products	$	66,306		$	51,530
Natural gas		34,817			35,344
Materials handling		10,184			8,077
Other operations		2,983			1,336

Adjusted gross margin		114,290			96,287
Reconciliation to operating income(2):
Add: unrealized gain (loss) on inventory(3)		(3,534	)		5,866
Add: unrealized gain (loss) on natural gas transportation contracts(4)		(2,771	)		28,127
Operating costs and expenses not allocated to operating segments:
Operating expenses		(18,883	)		(16,838	)
Selling, general and administrative		(32,381	)		(27,411	)
Depreciation and amortization		(4,992	)		(3,955	)

Operating income		51,729			82,076
Other income		514			—
Interest income		112			110
Interest expense		(7,766	)		(8,016	)
Income tax provision		(650	)		(1,038	)

Net income	$	43,939		$	73,132

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. The Partnership adjusts its segment results for the impact of unrealized hedging gains and losses with regard to refined products and natural gas inventory and natural gas transportation contracts relating to the underlying commodity derivative hedges, which are not marked to market for the purpose of recording unrealized gains or losses in net income (loss). These adjustments align the unrealized hedging gains and losses to the period in which the revenue from the sale of inventory and the utilization of transportation contracts relating to those hedges is realized in net income.

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

(3)

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

(4)

The unrealized hedging (gain) loss on natural gas transportation contracts represents the Partnership’s estimate of the change in fair value of the natural gas transportation contracts which are not recorded in net income (loss) until the transportation is utilized in the future (i.e., when natural gas is delivered to the customer), as these contracts are executory contracts that do not qualify as derivatives. As the fair value of the natural gas transportation contracts decline or appreciate, the offsetting physical or financial derivative will also appreciate or decline creating ‘unmatched’ unrealized hedging losses (gains) in net income.

The Partnership had no single customer whose revenue was greater than 10% of total net sales for the three months ended March 31, 2015 and 2014, respectively. The Partnership’s foreign sales, primarily sales of refined products, asphalt and natural gas to its customers in Canada, were $58.1 million and $92.4 million for the three months ended March 31, 2015 and 2014, respectively.

Segment Assets

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

As of March 31, 2015 and December 31, 2014, goodwill for the refined products, natural gas, materials handling and other operations segments amounted to $36.6 million, $18.6 million, $6.9 million and $1.2 million, respectively.

8. Financial Instruments and Off-Balance Sheet Risk

Cash and Cash Equivalents, Accounts Receivable and Debt

As of March 31, 2015 and December 31, 2014, the carrying amounts of cash and cash equivalents and accounts receivable approximated fair value because of the short maturity of these instruments. As of March 31, 2015 and December 31, 2014, 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 can utilize derivatives to generate profits from changes in market prices. The Partnership enters into futures and over-the-counter (“OTC”) transactions either on regulated exchanges or in the OTC market. Futures contracts are exchange-traded contractual commitments to either receive or deliver a standard amount or value of a commodity at a specified future date and price, with some futures contracts based on cash settlement rather than a delivery requirement. Futures exchanges typically require margin deposits as security. OTC contracts, which may or may not require margin deposits as security, involve parties that have agreed either to exchange cash payments or deliver or receive the underlying commodity at a specified future date and price. The Partnership posts initial margin with futures transaction brokers, along with variation margin, which is paid or received on a daily basis, and is included in other current assets in 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 March 31, 2015 will settle prior to September 30, 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 or other comprehensive income 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. The Partnership did not have any transfers between Level 1 and Level 2 fair value measurement during the three months ended March 31, 2015.

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

The Partnership does not offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) against the fair value of derivative instruments executed with the same counterparty under the same master netting arrangement. The Partnership had no right to reclaim, or obligation to return, cash collateral as of March 31, 2015 or December 31, 2014.

The following table presents all financial assets and financial liabilities of the Partnership measured at fair value on a recurring basis as of March 31, 2015 and December 31, 2014:


	As of March 31, 2015
	Fair Value Measurement		Quoted Prices in Active Markets Level 1		Significant Other Observable Inputs Level 2		Significant Unobservable Inputs Level 3
Financial assets:
Commodity fixed forwards	$	169,186	$	—	$	169,186	$	—
Commodity swaps and options		112		—		112		—

Total	$	169,298	$	—	$	169,298	$	—

Financial liabilities:
Commodity exchange contracts	$	93	$	93	$	—	$	—
Commodity fixed forwards		47,508		—		47,508		—
Commodity swaps and options		7,055		—		7,055		—

Commodity derivatives		54,656		93		54,563		—
Interest rate swaps		987		—		987		—
Currency swaps		42		—		42		—

Total	$	55,685	$	93	$	55,592	$	—


	As of December 31, 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 fixed forwards	$	229,679	$	—	$	229,679	$	—
Commodity swaps and options		74		—		74		—

Commodity derivatives		229,753		—		229,753		—
Interest rate swaps		137		—		137		—

Total	$	229,890	$	—	$	229,890	$	—

Financial liabilities:
Commodity exchange contracts	$	97	$	97	$	—	$	—
Commodity fixed forwards		80,080		—		80,080		—
Commodity swaps and options		8,424		—		8,424		—

Commodity derivatives		88,601		97		88,504		—
Interest rate swaps		553		—		553		—
Currency swaps		22		—		22		—

Total	$	89,176	$	97	$	89,079	$	—

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. The maximum amount of loss due to credit risk that the Partnership would incur if its counterparties failed completely to perform according to the terms of the contracts, based on the gross fair value of these financial instruments, was $169.3 million at March 31, 2015. Information related to these offsetting arrangements as of March 31, 2015 and December 31, 2014 is as follows:


	As of March 31, 2015
									Gross Amount Not Offset in
	Gross								the Balance Sheet
	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
Fair value of commodity derivative assets	$	169,298		$	—	$	169,298		$	(3,371	)	$	(1,147	)	$	164,780

Commodity derivative liabilities	$	(54,656	)	$	—	$	(54,656	)	$	3,371		$	—		$	(51,285	)
Interest rate swap derivative liabilities		(987	)		—		(987	)		—			—			(987	)
Currency swap derivative liabilities		(42	)		—		(42	)		—			—			(42	)

Fair value of derivative liabilities	$	(55,685	)	$	—	$	(55,685	)	$	3,371		$	—		$	(52,314	)


	As of December 31, 2014
									Gross Amount Not Offset in
	Gross								the Balance Sheet
	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	$	229,753		$	—	$	229,753		$	(4,831	)	$	(2,417	)	$	222,505
Interest rate swap derivative assets		137			—		137			—			—			137

Fair value of derivative assets	$	229,890		$	—	$	229,890		$	(4,831	)	$	(2,417	)	$	222,642

Commodity derivative liabilities	$	(88,601	)	$	—	$	(88,601	)	$	4,831		$	—		$	(83,770	)
Interest rate swap derivative liabilities		(553	)		—		(553	)		—			—			(553	)
Currency swap derivative liabilities		(22	)		—		(22	)		—			—			(22	)

Fair value of derivative liabilities	$	(89,176	)	$	—	$	(89,176	)	$	4,831		$	—		$	(84,345	)

The following table presents total realized and unrealized gains (losses) on derivative instruments utilized for commodity risk management purposes for the three months ended March 31, 2015 and 2014. Such amounts are included in cost of products sold (exclusive of depreciation and amortization) in the Condensed Consolidated Statements of Operations:


	Three Months Ended March 31,
	2015			2014
Refined products contracts	$	61,804		$	6,342
Natural gas contracts		(4,328	)		(13,693	)

Total	$	57,476		$	(7,351	)

There were no discretionary trading activities for the three months ended March 31, 2015 and 2014. The following table presents the gross volume of commodity derivative instruments outstanding as of March 31, 2015 and December 31, 2014:


	As of March 31, 2015						As of December 31, 2014
	Refined Products			Natural Gas			Refined Products			Natural Gas
	(Barrels)			(MMBTUs)			(Barrels)			(MMBTUs)
Long contracts		8,711			117,614			10,823			131,376
Short contracts		(11,793	)		(71,417	)		(15,434	)		(82,796	)

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 March 31, 2015, the Partnership held six interest rate swaps with a total notional value of $175.0 million whose swap periods began 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 months ended March 31, 2015 and 2014.

The Partnership records unrealized gains and losses on its interest rate swaps as a component of accumulated other comprehensive loss, net of tax, which is reclassified to earnings as interest expense when the payments are made. As of March 31, 2015, the amount of unrealized losses, net of tax, expected to be reclassified to earnings during the following twelve-month period was approximately $0.5 million.

Currency Derivatives

Kildair enters into forward currency contracts to manage the risk of currency rate fluctuations between its Canadian dollar denominated activity and the U.S. dollar, which is its functional currency. At March 31, 2015, Kildair has entered into a series of forward currency swaps that mature through April 2015. The contracts obligate Kildair to purchase $10.0 million in Canadian dollars at an exchange rate of 1.2734 to 1. The Canadian to U.S. dollar exchange rate was 1.2666 to 1 at March 31, 2015.

9. Commitments and Contingencies

Legal, Environmental and Other Proceedings

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

10. Equity-Based Compensation

On July 11, 2014, the board of directors of the General Partner approved that under the annual bonus program which is provided to substantially all employees, bonuses for the majority of participants will be settled in cash with others receiving a combination of cash and common units. The Partnership records the 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. During the three months ended March 31, 2015, $4.9 million of the annual bonus expense accrual as of December 31, 2014 was settled by issuing 200,775 common units and the Partnership withheld from the recipients 67,141 common units (estimated fair value of $1.7 million) to satisfy minimum tax withholding obligations. The Partnership estimates that $3.3 million of the annual bonus expense recorded during the three months ended March 31, 2015 will be settled in common units.

The board of directors of the General Partner grants performance-based phantom unit awards to key employees that vest 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 (between 0 to 200 percent) of the target phantom units granted, based on the Partnership’s 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 the performance-based phantom units granted is estimated based on a Monte Carlo model that estimated the most likely performance outcome based on the terms of the award. The key inputs in the model include the market price of the Partnership’s common units as of the valuation date, the historical volatility of the market price of the Partnership’s common units, the historical volatility of the market price of the common units or common stock of the peer companies and the correlation between changes in the market price of the Partnership’s common units and those of the peer companies.

The fair value of the performance-based phantom units granted on March 5, 2015 was estimated to be $4.5 million based on a Monte Carlo simulation using a weighted average volatility of 32.9% and a weighted average risk free rate of 0.98%.

Based on the total unitholder return calculation, the performance-based phantom units with a performance period ending as of December 31, 2014 vested at the 200% level and as a result 74,048 common units were issued during the three months ended March 31, 2015. In connection with these vested awards, the Partnership withheld from the recipients 24,605 units (estimated fair value of $0.6 million) to satisfy minimum tax withholding obligations.

Total unrecognized compensation cost related to performance-based phantom units totaled $5.4 million as of March 31, 2015, which is expected to be recognized over a period of 33 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.

A summary of the Partnership’s unit awards subject to vesting for the three months ended March 31, 2015 is set forth below:


	Restricted Units				Time Based 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, 2014		4,444	$	17.33		23,685		$	20.16			111,075	$	36.88
Granted		—		—		—			—			141,000	$	31.58
Forfeited		—		—		—			—			—		—
Vested		—		—		(13,766	)	$	(20.16	)		—		—

Nonvested at March 31, 2015		4,444	$	17.33		9,919		$	20.16			252,075	$	33.92

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


	Common Units
	Public		Sprague Holdings		Subordinated Units
Balance as of December 31, 2013		8,506,666		1,571,970		10,071,970
Employee and Director vested awards		27,401		—		—
Units issued in connection with Castle acquisition		243,855		—		—
Units issued in connection with Kildair acquisition		—		462,408		—

Balance as of December 31, 2014		8,777,922		2,034,378		10,071,970

Units issued in connection with employee bonus		133,634		—		—
Units issued in connection with employee phantom awards		58,358		—		—

Balance as of March 31, 2015		8,969,914		2,034,378		10,071,970

Unit-based compensation recorded in unitholders’ equity for the three months ended March 31, 2015 and 2014 was $0.8 million and $0.5 million, respectively, and is included in selling, general and administrative expenses. Units issued under the Partnership’s LTIP are newly issued.

11. Earnings Per Unit

Earnings per unit applicable to limited partners (including subordinated unitholders) is computed by dividing limited partners’ interest in net income, after deducting any incentive distributions, by the weighted-average number of outstanding common and subordinated units. The Partnership’s net income is allocated to the limited partners in accordance with their respective 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 no units were outstanding prior to October 30, 2013. Earnings in excess of distributions are allocated to the limited partners based on their respective ownership interests. Payments made to the Partnership’s unitholders are determined in relation to actual distributions declared and are not based on the net income allocations used in the calculation of earnings per unit.

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

The following table shows the weighted average common units outstanding used to compute net income per common unit for the three months ended March 31, 2015 and 2014:


	Three Months Ended March 31,
	2015		2014
Weighted average limited partner common units - basic		10,897,488		10,072,186
Dilutive effect of unvested restricted and phantom units		167,022		990

Weighted average limited partner common units - dilutive		11,064,510		10,073,176

The following table presents the Partnership’s basic earnings per common and subordinated unit for the three months ended March 31, 2015 and 2014:


	Three Months Ended March 31, 2015
	Common Units		Subordinated Units		Total
	(in thousands, except for per unit amounts)
Limited partners’ interest in net income					$	43,939

Distributions declared	$	5,204	$	4,759	$	9,963
Assumed net income from operations after distributions		17,630		16,346		33,976

Assumed net income to be allocated	$	22,834	$	21,105	$	43,939

Earnings per unit - basic	$	2.10	$	2.10
Earnings per unit - diluted	$	2.06	$	2.10

	Three Months Ended March 31, 2014
	Common Units		Subordinated Units		Total
	(in thousands, except for per unit amounts)
Limited partners’ interest in net income					$	75,335

Distributions declared	$	4,165	$	4,155	$	8,320
Assumed net income from operations after distributions.		33,503		33,512		67,015

Assumed net income to be allocated	$	37,668	$	37,667	$	75,335

Earnings per unit - basic	$	3.74	$	3.74
Earnings per unit - diluted	$	3.74	$	3.74

12. Partnership Distributions

The Partnership agreement sets forth the calculation to be used to determine the amount and priority of cash distributions that the common and subordinated unitholders will receive.

On January 28, 2015, the Partnership declared a cash distribution totaling $9.6 million, or $0.4575 per unit for the three months ended December 31, 2014. Such distribution was paid on February 13, 2015, to unitholders of record on February 9, 2015.

13. Subsequent Event

On April 29, 2015, the Partnership declared a cash distribution totaling $10.0 million, or $0.4725 per unit for the three months ended March 31, 2015, payable on May 15, 2015, to unitholders of record on May 11, 2015.

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 March 31, 2015 (the “quarterly report”), including without limitation, our discussion and analysis of our financial condition and results of operations, and any information incorporated by reference, 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 heating oil and residual oil 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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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 U.S. 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, 2014.

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”, our 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 interest in Sprague Resources LP (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. 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.

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the Partnership’s financial statements and related notes thereto as of and for the three months ended March 31, 2015 contained elsewhere in this Quarterly Report and the audited financial statements and related notes thereto as of and for the year ended December 31, 2014, included in our Annual Report on Form 10-K for the year ended December 31, 2014, as filed with the Securities Exchange Commission (the “SEC”) on March 16, 2015 (the “2014 Annual Report”).

A reference to a “Note” herein refers to the accompanying Notes to the Condensed 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 in June 2011 by Sprague Holdings and our General Partner to engage in the purchase, storage, distribution and sale of refined products and natural gas, and to provide storage and handling services for a broad range of materials. 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 19 refined products and materials handling terminals strategically located throughout the Northeast United States and in Quebec, Canada that have a combined storage capacity of 14.1 million barrels for refined products and other liquid materials, as well as 1.5 million square feet of materials handling capacity. We also have an aggregate of 2.1 million barrels of additional storage capacity attributable to 46 storage tanks not currently in service. These tanks are not necessary for the operation of our business at current levels. In the event that such additional capacity were desired, additional time and capital would be required to bring any of such storage tanks into service. Furthermore, we have access to more than 60 third-party terminals in the Northeast United States through which we sell or distribute refined products pursuant to rack, exchange and throughput agreements.

We operate under four business segments: refined products, natural gas, materials handling and other operations. 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 “Adjusted Gross Margin and Adjusted EBITDA.” For a reconciliation of adjusted gross margin to the GAAP measure most directly comparable thereto, see “Results of Operations.”

On October 1, 2012, our Predecessor acquired 9047-1137 Quebec Inc. (“Kildair”). Kildair owns a terminal in Sorel-Tracy, Quebec, on the St. Lawrence River where it maintains 3.3 million barrels of residual fuel, asphalt, and crude oil storage. Kildair’s primary businesses include marketing of residual fuel oil both locally and for export, marketing of asphalt including polymer modified grades, and crude-by-rail handling services. Kildair’s terminal has blending infrastructure allowing the ability to process a wide range of varying quality blend components.

In connection with the completion on October 30, 2013 of the IPO, Axel Johnson Inc. 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, its ownership of 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 by Sprague Holdings and were recorded at the Parent’s historical cost, as the foregoing transactions are among entities under common control.

On December 9, 2014, we acquired all of the equity interest in Kildair through the acquisition of the equity interests of Kildair’s parent, Sprague Canadian Properties LLC, from a wholly owned subsidiary of Sprague Holdings. As this transaction represents a transfer of entities under common control, the Condensed Consolidated Financial Statements and related information presented herein have been recast to include the historical results of Kildair for all periods presented where Kildair was controlled by Axel Johnson, which commenced on October 1, 2012. Limited partners’ interest in net income as well as the related per unit amounts have not been recast for the three months ended March 31, 2014.

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. As of March 31, 2015, Sprague Holdings owns 2,034,378 common units and 10,071,970 subordinated units, representing an aggregate 57% 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. Sprague Holdings also holds the 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.

Our refined products segment purchases a variety of refined products, such as heating oil, diesel fuel, residual fuel oil, kerosene, jet fuel, gasoline and asphalt (primarily from refining companies, trading organizations and producers), and sells them to our customers. We have wholesale customers who resell the refined products we sell to them and commercial customers who consume the refined products we sell to them. Our wholesale customers consist of more than 1,000 heating oil retailers and diesel fuel and gasoline resellers. Our commercial customers include federal and state agencies, municipalities, regional transit authorities, large industrial companies, real estate management companies, hospitals, educational institutions and asphalt paving companies. For the three months ended March 31, 2015 and 2014, we sold 726.4 million and 588.8 million gallons of refined products, respectively, and our refined products segment accounted for 58% and 54% of our adjusted gross margin, respectively.

We also purchase, sell and distribute natural gas to approximately 15,000 commercial and industrial customer locations across 13 states in the Northeast and Mid-Atlantic United States. We purchase the natural gas we sell from natural gas producers and trading companies. For the three months ended March 31, 2015 and 2014, we sold 20.0 Bcf and 16.5 Bcf of natural gas, respectively, which accounted for 30% and 37% 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, crude oil, caustic soda, tallow, pulp and heavy equipment. For the three months ended March 31, 2015, we offloaded, stored and/or prepared for delivery 0.6 million short tons of products and 74.8 million gallons of liquid materials. For the three months ended March 31, 2014, we offloaded, stored and/or prepared for delivery 0.7 million short tons of products and 66.8 million gallons of liquid materials. For the three months ended March 31, 2015 and 2014, our materials handling segment accounted for 9% and 8% of our adjusted gross margin respectively.

Our other operations segment includes the marketing and distribution of coal conducted in our Portland, Maine terminal and commercial trucking activity. For the three months ended March 31, 2015 and 2014, our other operations segment accounted for 3% and 1% 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.

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

EBITDA

We define EBITDA as net income (loss) 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, trade suppliers, research analysts and commercial banks 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;

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Repeatable operating performance that is not distorted by non-recurring items or market volatility; 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 (loss), 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 (loss) and operating income.

Adjusted Gross Margin and Adjusted EBITDA

Management utilizes adjusted gross margin and adjusted EBITDA to assist it in reviewing our financial results and managing our business segments. We define adjusted gross margin as net sales less cost of products sold (exclusive of depreciation and amortization) increased by unrealized hedging losses and decreased by unrealized hedging gains, in each case with respect to refined products and natural gas inventory and natural gas transportation contracts. We define adjusted EBITDA as EBITDA increased by unrealized hedging losses and decreased by unrealized hedging gains, in each case with respect to refined products and natural gas inventory and natural gas transportation contracts, decreased by gains on acquisition of businesses, increased by the write-off of deferred offering costs. 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 investors, trade suppliers, research analysts and commercial banks 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 (loss), income from operations, cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP.

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. Operating expenses for the three months ended March 31, 2014 have been recast to include the historical results of Kildair.

Selling, General and Administrative Expenses

Our SG&A includes employee salaries and benefits, discretionary bonus, marketing costs, corporate overhead, professional fees, information technology and office space expenses. Commencing on October 30, 2013, employee wages, related employee expenses and certain rental costs included in our SG&A expenses are incurred on our behalf by our General Partner and reimbursed by us. SG&A expenses for the three months ended March 31, 2014 have been recast to include the historical results of Kildair.

Heating Degree Days

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

Hedging Activities

We 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 primarily based in New York Harbor, or NYH, 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 most applicable 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 show only the impact of hedging gains and losses actually realized in the period being reviewed. By making such adjustments, as reflected in adjusted gross margin and adjusted EBITDA, we believe that we are able to align more closely hedging gains and losses to the period in which the revenue from the sale of inventory and income from transportation contracts relating to those hedges is realized.

Trends and Factors that Impact our Business

This section identifies certain factors and industry-wide trends that may affect our financial performance and results of operations.

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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, local and foreign laws and regulations regulating product quality specifications, emissions in the air, discharges to land and water, and the generation, handling, treatment, and disposal of hazardous waste and other materials. The trend in regulation is towards additional restrictions and limitations on activities that may affect the environment. Compliance with laws and regulations may increase our overall cost of business including our capital cost to maintain and upgrade equipment and facilities.

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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 United States, leading to expanded use of natural gas in our marketing area. Natural gas usage in the Northeast United States 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 United States 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 United States.

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Absolute price increase or decreases can impact demand and credit risk. Commodity prices in both our refined products and natural gas segments can vary sharply due to market conditions. As commodity product prices rise, we can experience reduced demand as customers engage in conservation efforts, are exposed to a higher level of credit risk to meet customer requirements, and working capital costs for holding inventory and accounts receivables increase. In a lower commodity price environment our customers would be generally less prone to engage in conservation efforts, we experience lower credit risk, and working capital costs to hold inventory and finance accounts receivable decrease.

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Seasonality and weather conditions. Our financial results are impacted by seasonality in our businesses and are generally better during the winter months, primarily because a material part of our business consists of supplying heating oil, residual fuel oil and natural gas for space heating purposes during the winter. For example, over the 36-month period ended March 31, 2015, we generated an average of approximately 72% of our total heating oil and residual fuel oil net sales during the months of November through March in the Northeast United States. In addition, weather conditions, particularly during these five months, have a significant impact on the demand for our products. Warmer-than-normal temperatures during these months in our areas of operations can decrease the total volume of heating oil, residual fuel oil and natural gas we sell and the adjusted gross margins realized on those sales, whereas colder-than-normal temperatures increase demand for those products and the associated adjusted gross margins.

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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 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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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, in the future, to fund our growth. In addition, interest rates could be higher than current levels, causing our financing costs to increase accordingly. 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. During the 24 months ended March 31, 2015, we hedged approximately 27% of our floating-rate debt with fixed-for-floating interest rate swaps. 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. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our common units, and a rising interest rate environment could have an adverse impact on our unit price and our ability to issue additional equity to make acquisitions, reduce debt or for other purposes.

Results of Operations

Our acquisition of Kildair on December 9, 2014 represented a transfer of entities under common control. The information presented herein has been recast to include the historical results of Kildair for all periods presented where Kildair was controlled by Axel Johnson.

The following tables present our volume, net sales, and adjusted gross margin by segment, as well our EBITDA, adjusted EBITDA, and information on weather conditions, for the three months ended March 31, 2015 and 2014:


	Three Months Ended March 31,
	2015			2014
	(in thousands)
Volumes:
Refined products (gallons)		726,432			588,756
Natural gas (MMBtus)		20,013			16,496
Materials handling (short tons)		585			694
Materials handling (gallons)		74,760			66,822
Net Sales:
Refined products	$	1,431,845		$	1,844,973
Natural gas		146,679			134,340
Materials handling		10,184			8,079
Other operations		9,650			7,307

Total net sales	$	1,598,358		$	1,994,699

Adjusted Gross Margin:
Refined products	$	66,306		$	51,530
Natural gas		34,817			35,344
Materials handling		10,184			8,077
Other operations		2,983			1,336

Total adjusted gross margin	$	114,290		$	96,287

Reconciliation to Operating Income:
Total adjusted gross margin	$	114,290		$	96,287
Add: unrealized gain (loss) on inventory (1)		(3,534	)		5,866
Add: unrealized gain (loss) on natural gas transportation contracts (2)		(2,771	)		28,127
Operating expenses		(18,883	)		(16,838	)
Selling, general and administrative		(32,381	)		(27,411	)
Depreciation and amortization		(4,992	)		(3,955	)

Operating income	$	51,729		$	82,076
Other income		514			—
Interest income		112			110
Interest expense		(7,766	)		(8,016	)
Income tax provision		(650	)		(1,038	)

Net income	$	43,939		$	73,132


	Three Months Ended March 31,
	2015			2014
	(in thousands)
Reconciliation of Net Income to Adjusted EBITDA
Net income	$	43,939		$	73,132
Add:
Interest expense, net		7,654			7,906
Tax expense		650			1,038
Depreciation and amortization		4,992			3,955

EBITDA (3):	$	57,235		$	86,031

Add: unrealized (gain) loss on inventory (1)		3,534			(5,866	)
Add: unrealized (gain) loss on natural gas transportation contracts (2)		2,771			(28,127	)

Adjusted EBITDA (3):	$	63,540		$	52,038

Other Data:
Normal heating degree days(4)		3,274			3,274
Actual heating degree days		3,881			3,606
Variance from normal heating degree days		18.5	%		10.1	%
Variance from prior period actual heating degree days		7.6	%		14.5	%

(1)

(2)

The unrealized hedging (gain) loss on natural gas transportation contracts represents the Partnership’s estimate of the change in fair value of the natural gas transportation contracts which are not recorded in net income until the transportation is utilized in the future (i.e., when natural gas is delivered to the customer), as these contracts are executory contracts that do not qualify as derivatives. As the fair value of the natural gas transportation contracts decline or appreciate, the offsetting physical or financial derivative will also appreciate or decline creating ‘unmatched’ unrealized hedging losses (gains) in net income (loss).

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

(4)	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 March 31, 2015 compared to Three Months Ended March 31, 2014

Our results of operations for the three months ended March 31, 2015 reflect decreasing net sales and increasing sales volumes and adjusted unit gross margin in our refined products segment; increasing net sales, sales volumes and decreasing adjusted unit gross margin in our natural gas segment; and increasing net sales and adjusted gross margin in our materials handling segment.

Adjusted gross margin for the three months ended March 31, 2015 reflects increasing adjusted unit gross margin for refined products and decreasing adjusted unit gross margin for natural gas.


	Three Months Ended
	March 31,				Increase/(Decrease)
	2015		2014		$			%
	($ in thousands, except unit adjusted gross margin)
Volumes:
Refined products (gallons)		726,432		588,756		137,676			23	%
Natural gas (MMBtus)		20,013		16,496		3,517			21	%
Materials handling (short tons)		585		694		(109	)		(16	)%
Materials handling (gallons)		74,760		66,822		7,938			12	%
Net Sales:
Refined products	$	1,431,845	$	1,844,973	$	(413,128	)		(22	)%
Natural gas		146,679		134,340		12,339			9	%
Materials handling		10,184		8,079		2,105			26	%
Other operations		9,650		7,307		2,343			32	%

Total net sales	$	1,598,358	$	1,994,699	$	(396,341	)		(20	)%

Adjusted Gross Margin:
Refined products	$	66,306	$	51,530	$	14,776			29	%
Natural gas		34,817		35,344		(527	)		(1	)%
Materials handling		10,184		8,077		2,107			26	%
Other operations		2,983		1,336		1,647			123	%

Total adjusted gross margin	$	114,290	$	96,287	$	18,003			19	%

Adjusted Unit Gross Margin:
Refined products	$	0.091	$	0.088	$	0.003			3	%
Natural gas	$	1.740	$	2.143	$	(0.403	)		(19	)%

Refined Products

Refined products net sales for the three months ended March 31, 2015 decreased $413.1 million, or 22% as compared to the three months ended March 31, 2014. This was the result of a 37% reduction in average refined products sales price for the three months ended March 31, 2015 offset by increased volumes driven by factors discussed below. The lower sales prices reflect the generally weaker refined products price environment. For example, the average prompt month NYMEX ULSD closing prices for the three months ending March 31, 2015 was 40% lower than the corresponding average price for the same period in 2014.

Refined products sales volumes for the three months ended March 31, 2015 increased 137.7 million gallons or 23% as compared to the three months ended March 31, 2014. The majority of this increase was due to higher distillate sales, with volumes increasing by 86.6 million gallons, or 18%, period over period. This gain was largely a result of higher heating oil volumes, in particular due to sales at the Bronx, NY terminal acquired from Castle Oil Corporation (“Castle”) in December 2014. Contributing to the volume increase was also higher sales in the Providence, RI and New Haven, CT markets where the Partnership operated out of terminals with expanded capabilities compared to 2014. In addition to the incremental sales at the new locations, colder weather during the first three months of 2015 contributed to the higher heating oil volumes. The period over period increase in heating degree days of more than 7% reflects the colder weather observed during the first three months of 2015 compared to the same period in 2014. Additionally, gasoline sales volumes for the three months ended March 31, 2015 increased 11.2 million gallons, or 27%, as compared to three months ended March 31, 2014. Contributing to the volume gains were the declining spot prices in the early part of the quarter, leading to improved intra-day sales opportunities on the Sprague Real-Time platform. Residual fuel oil sales volumes increased 39.9 million gallons, or 55%, for the three months ended March 31, 2015 as compared to the same period in 2014. The gain in residual fuel volumes was primarily due to the addition of the volumes sold from the Bronx, NY terminal following the Castle acquisition.

Refined products adjusted gross margin for the three months ended March 31, 2015 increased $14.8 million or 29% as compared to the three months ended March 31, 2014. This increase was primarily attributable to the 23% gain in refined products sales volumes above. Overall adjusted unit margins increased by 3% period over period, with the improvement largely driven by higher adjusted unit margins for heating oil due to the supply-constrained environment.

Natural Gas

Natural gas net sales for the three months ended March 31, 2015 increased $12.3 million or 9%, as compared to the three months ended March 31, 2014. This was primarily due to a 21% gain in volumes. The key factor leading to the higher volumes was the incremental sales in the first quarter of 2015 resulting from the Metromedia Gas & Power Inc. (“Metromedia Energy”) acquisition completed in October 2014. This volume gain was partially offset by a 10% reduction in natural gas sales prices due to a generally weaker energy price environment for the three months ended March 31, 2015 as compared to the three months ended March 31, 2014.

Natural gas adjusted gross margin for the three months ended March 31, 2015 declined $0.5 million or 1% as compared to the three months ended March 31, 2014. Despite colder temperatures in the Northeast compared to last year, the region experienced less cash market volatility, resulting in fewer optimization opportunities related to our transportation and storage assets during the three months ended March 31, 2015 as compared to the three months ended March 31, 2014.

Materials Handling

Materials handling net sales for the three months ended March 31, 2015 increased $2.1 million, or 26% as compared to the three months ended March 31, 2014. This increase was primarily due to the crude handling project at Kildair which commenced in July 2014 that increased liquid bulk handling revenue substantially, while break bulk and dry bulk volumes were modestly higher at other Partnership facilities.

Materials handling adjusted gross margin for the three months ended March 31, 2015 increased $2.1 million, or 26% as compared to the three months ended March 31, 2014. This increase was primarily a result of Kildair’s crude handling activities. There were also some variations in other bulk handling activity, primarily driven by vessel timing differences. As a result of earlier than expected deliveries of windmill components and liquid asphalt to meet this summer’s construction demand occurred. This was largely offset by delays in salt and slag deliveries as regional availability of bulk cargo vessels was constrained.

Other Operations

Net sales from other operations for the three months ended March 31, 2015 increased $2.3 million or 32% as compared to the three months ended March 31, 2014. The higher sales were primarily due to a combination of increased coal volumes due partly to weather driven demand for coal-related power generation as well as the inclusion of the oil burner service business obtained as part of the Castle acquisition.

Adjusted gross margins from other operations for the three months ended March 31, 2015 increased $1.6 million or 123% as compared to the three months ended March 31, 2014. Similar to the net sales increase, this gain was attributable to a combination of additional coal volumes plus the incremental margin associated with the oil burner service activity that was not part of the Partnership’s business for the three months ended March 2014.

Operating Costs and Expenses

Three Months Ended March 31, 2015 compared to Three Months Ended March 31, 2014


	Three Months Ended March 31,				Increase/(Decrease)
	2015		2014		$		%
			($ in thousands)
Operating expenses	$	18,883	$	16,838	$	2,045		12	%
Selling, general and administrative expenses	$	32,381	$	27,411	$	4,970		18	%
Depreciation and amortization	$	4,992	$	3,955	$	1,037		26	%

Operating Expenses. Operating expenses for the three months ended March 31, 2015 increased $2.0 million, or 12%, as compared to the three months ended March 31, 2014. Of this increase approximately $2.4 million was due to expenses at our recently acquired Castle terminal partially offset by decrease of $0.4 million primarily related to utilities and terminal maintenance.

Selling, General and Administrative Expenses. Selling, general and administrative expenses for the three months ended March 31, 2015, increased $5.0 million, or 18%, as compared to the three months ended March 31, 2014. Of this increase $4.2 million was due to selling, general and administrative expenses related to the Metromedia Energy and Castle acquisitions with the remaining increase of $0.8 million primarily related to expenses associated with mergers and acquisition activities.

Depreciation and Amortization. Depreciation and amortization for the three months ended March 31, 2015 increased $1.0 million, or 26% as compared to the three months ended March 31, 2014. Of this increase $0.7 million was due to the Metromedia Energy and Castle acquisitions with the remaining increase of $0.3 million primarily due to the depreciation of the assets related to Kildair’s crude storage and handling project which was placed in service in June 2014.

Interest Expense, net

Three Months Ended March 31, 2015 compared to Three Months Ended March 31, 2014


	Three Months Ended March 31,				Increase/(Decrease)
	2015		2014		$			%
			($ in thousands)
Interest expense, net	$	7,654	$	7,906	$	(252	)		(3	)%

Interest Expense, net. Interest expense, net for the three months ended March 31, 2015 decreased $0.3 million, or 3%, as compared to the three months ended March 31, 2014. This decrease was primarily due to the expiration of interest rate swaps related to a portion of the variable rate debt obligations offset by increased amortization of debt issuance costs associated with the Partnership’s credit facility.

Liquidity and Capital Resources

Liquidity

Our primary liquidity needs are to fund our working capital requirements, operating expenses, capital expenditures and quarterly distributions. Cash generated from operations, our borrowing capacity under our Credit Agreement (as defined below) and potential future issuances of additional partnership interests or debt securities are our primary sources of liquidity. At March 31, 2015, the Partnership had working capital of $293.3 million.

As of March 31, 2015, the borrowing base capacity under the Partnership’s working capital facility was $639.1 million. As of March 31, 2015, working capital borrowings were $416.1 million and outstanding letters of credit were $36.1 million, providing us with $186.9 million in undrawn borrowing capacity under the working capital facility.

As of March 31, 2015, the Partnership had $311.6 million in outstanding borrowings under our acquisition facility, resulting in $88.4 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 three months ended March 31, 2015, the amount the Partnership had drawn under the working capital facility fluctuated from a low of $406.0 million to a high of $563.2 million.

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

Credit Agreement

On December 9, 2014, in connection with the Kildair acquisition, Sprague Operating Resources LLC, the operating company of the Partnership, Sprague Resources ULC and Kildair entered into an amended and restated revolving credit agreement (the “Credit Agreement”). Capitalized terms used but not otherwise defined in this section entitled “Credit Agreement” are used as defined in the Credit Agreement. This $1.5 billion Credit Agreement will mature on December 9, 2019. The revolving credit facilities under the Credit Agreement contain, among other items, the following:

•

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

•

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

•

A revolving acquisition facility of up to $400.0 million to be used for loans and letters of credit to fund capital expenditures and acquisitions and other general corporate purposes related to the Partnership’s current businesses; and,

•

Subject to certain conditions, the U.S. dollar and multicurrency revolving working capital facilities may be increased by $200.0 million in the aggregate. Additionally, subject to certain conditions, the revolving acquisition facility may be increased by $200.0 million.

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

Indebtedness under the Credit Agreement will bear interest, at the Partnership’s option, at a rate per annum equal to either the Eurocurrency Rate (which is the LIBOR Rate for loans denominated in U.S. dollars and CDOR for loans denominated in Canadian dollars, in each case adjusted for certain regulatory costs) for interest periods of one, two, three or six months plus a specified margin or an alternate rate plus a specified margin.

The specified margin for the working capital facilities under the Credit Agreement will range, based upon the percentage utilization of this facility, from 1.00% to 1.50% for loans bearing interest at the alternative Base Rate and from 2.00% to 2.50% for loans bearing interest at the Eurocurrency Rate and for letters of credit issued under the U.S. dollar working capital facility or the multicurrency working capital facility. The specified margin for the acquisition facility under the Credit Agreement will range, based on the Partnership’s consolidated total leverage ratio, from 2.00% to 2.25% for loans bearing interest at the alternate Base Rate and from 3.00% to 3.25% for loans bearing interest at the Eurocurrency Rate and for letters of credit issued under the acquisition facility. In addition, the Partnership will incur a commitment fee on the unused portion of the facilities at a rate ranging from 0.375% to 0.50% per annum.

The Credit Agreement contains various covenants and restrictive provisions that, among other things, prohibit the Partnership from making distributions to unitholders if any event of default occurs or would result from the distribution or if the Partnership would not be in pro forma compliance with its financial covenants after giving effect to the distribution. In addition, the Credit Agreement contains various covenants that are usual and customary for a financing of this type, size and purpose, including, among others:

•

a minimum consolidated EBITDA-to-fixed charge ratio of 1.2:1.0;

•

a requirement of minimum consolidated Net Working Capital of $35,000,000;

•

a maximum consolidated total leverage-to-EBITDA ratio of 5.5:1.0 for any fiscal quarter ending on or prior to June 30, 2015 and a maximum consolidated total leverage-to-EBITDA ratio of 4.75:1.0 thereafter;

•

maximum consolidated senior secured leverage-to-EBITDA ratio of 4.5:1.0 for any fiscal quarter ending on or prior to June 30, 2015 and a maximum consolidated senior secured leverage-to-EBITDA ratio of 3.75:1.0 thereafter; and,

•

covenants limiting the ability of the Partnership and its subsidiaries to incur debt, grant liens, make certain investments or acquisitions, dispose of assets, and incur additional indebtedness.

The Credit Agreement also contains events of default that are usual and customary for a financing of this type, size and purpose including, among others, non-payment of principal, interest or fees, violation of certain covenants, material inaccuracy of representations and warranties, bankruptcy and insolvency events, cross-payment default and cross-accelerations, material judgments and events constituting a change of control. If an event of default exists under the Credit Agreement, the lenders will be able to terminate the lending commitments, accelerate the maturity of the Credit Agreement and exercise other rights and remedies with respect to the collateral.

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 three months ended March 31, 2015, we incurred a total of $1.4 million in maintenance capital expenditures and we spent $2.1 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 through our acquisition line or other long-term borrowings and/or equity offerings.

Cash Flows


	Three Months Ended March 31,
	2015			2014
	($ in thousands)
Net cash provided by operating activities	$	122,418		$	90,503
Net cash used in investing activities	$	(3,191	)	$	(5,575	)
Net cash used in financing activities	$	(101,556	)	$	(80,161	)

Operating Activities

Net cash provided by operating activities for the three months ended March 31, 2015 was $122.4 million. This was primarily driven by a decrease of $172.6 million in inventories as a result of strong sales volumes, $43.9 million in net income and a decrease of $26.5 million in derivative instruments relating to the ratable liquidation of the Partnership’s fixed forward contracts as we come out of the peak season, partially offset by an increase of $53.5 million in accounts receivable relating to the persistent cold weather and strong sales during the period and additional marketing activities from our 2014 acquisitions, as well as a reduction of $80.4 million in accounts payable and accrued liabilities primarily relating to the timing of invoice payments for product purchases.

Net cash provided by operating activities for the three months ended March 31, 2014 was $90.5 million. Cash flow from operations was driven by net income of $73.1 million and a decrease of $135.7 million in inventory offset by an increase of $59.9 million in accounts receivable due to the seasonal impact of the winter season of the Northeast United States. Accounts payable and accrued liabilities decreased $25.6 million because of the lower inventory levels.

Investing Activities

Net cash used in investing activities for the three months ended March 31, 2015 was $3.2 million of which $2.1 million related to expansion capital expenditures and $1.4 million related to maintenance capital expenditure projects across our terminal system. This was partially offset by $0.3 million of proceeds from the sale of assets.

Net cash used in investing activities for the three months ended March 31, 2014 was $5.6 million of which $4.2 million related to expansion capital expenditure projects at our Kildair terminal for a crude oil storage and handling construction project and $1.4 million related to other capital projects across our terminal system.

Financing Activities

Net cash used in financing activities for the three months ended March 31, 2015 was approximately $101.6 million, and primarily resulted from $87.0 million of net payments under our Credit Agreement due to reduced financing requirements from lower inventory levels and lower commodity prices. Distributions to unitholders were $9.6 million.

Net cash used in financing activities for the three months ended March 31, 2014 was approximately $80.2 million and primarily resulted from $74.0 million of net payments under the Credit Agreement due to reduced borrowing needs as a result of lower inventory levels. Distributions to unitholders were $5.7 million.

Impact of Inflation

Inflation in the United States and Canada has been relatively low in recent years and did not have a material impact on our results of operations for the three months ended March 31, 2015 and 2014.

New Accounting Guidance

In April 2015, the Financial Accounting Standards Board issued Accounting Standard Update 2015-06, Earnings Per Share (Topic 260): Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions (a consensus of the Emerging Issues Task Force). We are currently evaluating the potential impact of this guidance, however at this time we do not believe that the application of this ASU will result in changes to our presentation of earnings per unit or related disclosures in connection with our 2014 dropdown transaction. This guidance is effective for fiscal years beginning after December 15, 2015 and interim periods within those fiscal years and is to be applied on a retrospective basis.

In April 2015, the Financial Accounting Standards Board issued Accounting Standard Update 2015-03, Simplifying the Presentation of Debt Issuance Costs, which requires debt issuance costs to be presented in the balance sheet as a direct deduction from the carrying value of the associated debt liability, consistent with the presentation of a debt discount. This guidance is effective for annual reporting periods beginning after December 15, 2015, and interim periods within those fiscal years. As of March 31, 2015 and December 31, 2014, unamortized debt issuance costs were $16.9 million and $15.5 million, respectively.

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. We are currently evaluating the potential impact of this guidance which is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period.

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 months ended March 31, 2015 and 2014:


	Three Months Ended March 31,
	2015			2014
Refined products contracts	$	61,804		$	6,342
Natural gas contracts		(4,328	)		(13,693	)

Total	$	57,476		$	(7,351	)

Substantially all of our commodity derivative contracts outstanding as of March 31, 2015 will settle prior to September 30, 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 March 31, 2015, we held six interest rate swaps with a total notional value of $175.0 million whose swap periods began 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 bear interest, at our option, at a rate per annum equal to the Eurocurrency Rate (which means the LIBOR Rate) or 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 Eurocurrency 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 March 31, 2015, we hedged approximately 27% 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 income or loss, net of taxes, which is reclassified to earnings as interest expense when payments are made. We expect to continue to utilize interest rate swaps to manage our exposure to LIBOR interest rates. Based on a sensitivity analysis for the twelve months ended March 31, 2015, it was estimated that if short-term interest rates average 100 basis points higher (lower), interest expense would increase by approximately $4.3 million and decrease by approximately $0.6 million respectively. These amounts were estimated by considering the effect of the hypothetical short-term interest rates on variable-rate debt outstanding, adjusted for interest rate hedges.

Derivative Instruments

The following tables present all of our financial assets and financial liabilities measured at fair value on a recurring basis as of March 31, 2015:


	As of March 31, 2015
	Fair Value Measurement		Quoted Prices in Active Markets Level 1		Significant Other Observable Inputs Level 2		Significant Unobservable Inputs Level 3
Financial assets:
Commodity fixed forwards	$	169,186	$	—	$	169,186	$	—
Commodity swaps and options		112		—		112		—

Total	$	169,298	$	—	$	169,298	$	—

Financial liabilities:
Commodity exchange contracts	$	93	$	93	$	—	$	—
Commodity fixed forwards		47,508		—		47,508		—
Commodity swaps and options		7,055		—		7,055		—

Commodity derivatives		54,656		93		54,563		—
Interest rate swaps		987		—		987		—
Currency swaps		42		—		42		—

Total	$	55,685	$	93	$	55,592	$	—

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 March 31, 2015. 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 March 31, 2015, 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 three months ended March 31, 2015 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 2014 Annual Report, which could materially affect our business, financial condition or future results.

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

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).


Exhibit No.		Description

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 (File No. 001-36137)).

2.2***		Asset Purchase Agreement, dated November 4, 2014, by and among Sprague Operating Resources LLC, Castle Oil Corporation, Castle Port Morris Terminals, Inc., Castle Energy Solutions, LLC, Castle Fuels Corporation, Castle Supply & Marketing, Inc. and Castle Energy Solutions S.B., LLC (incorporated by reference to Exhibit 2.1 of Sprague Resources LP’s Current Report on Form 8-K filed November 5, 2014 (File No. 001-36137)).

2.3		Purchase Agreement, dated December 9, 2014, by and among Sprague Resources ULC, Sprague International Properties LLC, Sprague Canadian Properties LLC and Axel Johnson Inc. (incorporated by reference to Exhibit 2.1 of Sprague Resources LP’s Current Report on Form 8-K filed December 12, 2014 (File No. 001-36137)).

2.4		Consideration Agreement, dated December 9, 2014, between Sprague Resources LP and Sprague Resources ULC (incorporated by reference to Exhibit 2.2 of Sprague Resources LP’s Current Report on Form 8-K filed December 12, 2014 (File No. 001-36137)).

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

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

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

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

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

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

101.INS*		XBRL Instance Document

101.SCH*		XBRL Taxonomy Extension Schema Document

101.CAL*		XBRL Taxonomy Extension Calculation

101.DEF*		XBRL Taxonomy Extension Definition

101.LAB*		XBRL Taxonomy Extension Label Linkbase

101.PRE*		XBRL Taxonomy Extension Presentation

*	Filed herewith.

**	Furnished herewith in accordance with Item 601(b)(32) of Regulation S-K.

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

SIGNATURES

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


	SPRAGUE RESOURCES LP

	By:	Sprague Resources GP LLC,
		Its General Partner

Date: May 7, 2015		/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.


Exhibit No.		Description

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 (File No. 001-36137)).

2.2***		Asset Purchase Agreement, dated November 4, 2014, by and among Sprague Operating Resources LLC, Castle Oil Corporation, Castle Port Morris Terminals, Inc., Castle Energy Solutions, LLC, Castle Fuels Corporation, Castle Supply & Marketing, Inc. and Castle Energy Solutions S.B., LLC (incorporated by reference to Exhibit 2.1 of Sprague Resources LP’s Current Report on Form 8-K filed November 5, 2014 (File No. 001-36137)).

2.3		Purchase Agreement, dated December 9, 2014, by and among Sprague Resources ULC, Sprague International Properties LLC, Sprague Canadian Properties LLC and Axel Johnson Inc. (incorporated by reference to Exhibit 2.1 of Sprague Resources LP’s Current Report on Form 8-K filed December 12, 2014 (File No. 001-36137)).

2.4		Consideration Agreement, dated December 9, 2014, between Sprague Resources LP and Sprague Resources ULC (incorporated by reference to Exhibit 2.2 of Sprague Resources LP’s Current Report on Form 8-K filed December 12, 2014 (File No. 001-36137)).

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

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

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

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

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

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

101.INS*		XBRL Instance Document

101.SCH*		XBRL Taxonomy Extension Schema Document

101.CAL*		XBRL Taxonomy Extension Calculation

101.DEF*		XBRL Taxonomy Extension Definition

101.LAB*		XBRL Taxonomy Extension Label Linkbase

101.PRE*		XBRL Taxonomy Extension Presentation

*	Filed herewith.

**	Furnished herewith in accordance with Item 601(b)(32) of Regulation S-K.

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