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 June 30, 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 August 3, 2015

Table of Contents


		Page
PART I—FINANCIAL INFORMATION

Item 1.	Financial Statements:
	Condensed Consolidated Balance Sheets as of June 30, 2015 and December 31, 2014		1
	Unaudited Condensed Consolidated Statements of Operations for the three and six months ended June 30, 2015 and June 30, 2014		2
	Unaudited Condensed Consolidated Statements of Comprehensive (Loss) Income for the three and six months ended June 30, 2015 and June 30, 2014		3
	Unaudited Condensed Consolidated Statement of Unitholders’ Equity (Deficit) for the six months ended June 30, 2015		4
	Unaudited Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2015 and June 30, 2014		5
	Notes to Unaudited Condensed Consolidated Financial Statements		6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		22
Item 3.	Quantitative and Qualitative Disclosures about Market Risk		39
Item 4.	Controls and Procedures		41

PART II—OTHER INFORMATION

Item 1.	Legal Proceedings		42
Item 1A.	Risk Factors		42
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		42
Item 3.	Defaults Upon Senior Securities		42
Item 4.	Mine Safety Disclosures		42
Item 5.	Other Information		42
Item 6.	Exhibits		43
Signatures			44

Part I – FINANCIAL INFORMATION

Item 1 – Condensed Consolidated Financial Statements

Sprague Resources LP

Condensed Consolidated Balance Sheets

(in thousands except units)


	June 30,			December 31,
	2015			2014
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	9,230		$	4,080
Accounts receivable, net		164,110			289,424
Inventories		208,758			390,555
Fair value of derivative assets		134,221			229,890
Deferred income taxes		917			895
Other current assets		41,637			52,416

Total current assets		558,873			967,260
Property, plant and equipment, net		250,649			250,126
Assets held for sale		—			1,321
Intangibles, net		24,382			27,626
Other assets, net		24,934			30,219
Goodwill		63,288			63,288

Total assets	$	922,126		$	1,339,840

Liabilities and unitholders’ equity
Current liabilities:
Accounts payable	$	74,305		$	198,609
Accrued liabilities		45,467			63,816
Fair value of derivative liabilities		70,309			89,176
Due to General Partner and affiliates		10,906			15,340
Current portion of long-term debt		207,206			397,214
Current portion of capital leases		1,028			1,313

Total current liabilities		409,221			765,468

Commitments and contingencies (Note 9)		—			—
Long-term debt		334,841			418,356
Long-term capital leases		4,153			5,424
Other liabilities		17,642			17,884
Due to General Partner		1,036			988
Deferred income taxes		15,433			15,826

Total liabilities		782,326			1,223,946

Unitholders’ equity:
Common unitholders - public (8,969,914 units and 8,777,922 units issued and outstanding, as of June 30, 2015 and December 31, 2014, respectively)		182,009			171,055
Common unitholders - affiliated (2,034,378 units issued and outstanding)		(3,065	)		(5,566	)
Subordinated unitholders - affiliated (10,071,970 units issued and outstanding)		(27,381	)		(39,762	)
Accumulated other comprehensive loss, net of tax		(11,763	)		(9,833	)

Total unitholders’ equity		139,800			115,894

Total liabilities and unitholders’ equity	$	922,126		$	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 June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
Net sales	$	661,743		$	979,661		$	2,260,101		$	2,974,360
Cost of products sold (exclusive of depreciation and amortization)		616,059			953,788			2,106,432			2,818,207
Operating expenses		17,641			15,358			36,524			32,196
Selling, general and administrative		18,918			11,124			51,299			38,535
Depreciation and amortization		5,185			4,130			10,177			8,085

Total operating costs and expenses		657,803			984,400			2,204,432			2,897,023

Operating income (loss)		3,940			(4,739	)		55,669			77,337
Other income		—			—			514			—
Interest income		117			167			229			277
Interest expense		(6,459	)		(6,713	)		(14,225	)		(14,729	)

(Loss) Income before income taxes		(2,402	)		(11,285	)		42,187			62,885
Income tax (provision) benefit		(148	)		681			(798	)		(357	)

Net (loss) income		(2,550	)		(10,604	)		41,389			62,528
Add/(deduct):
Loss attributable to Kildair (Note 2)		—			1,110			—			3,313
Sprague Holdings’ incentive distributions		(49	)		—			(49	)		—

Limited partners’ interest in net (loss) income	$	(2,599	)	$	(9,494	)	$	41,340		$	65,841

Net (loss) income per limited partner unit:
Common - basic	$	(0.12	)	$	(0.47	)	$	1.97		$	3.27
Common - diluted	$	(0.12	)	$	(0.47	)	$	1.93		$	3.27
Subordinated - basic and diluted	$	(0.12	)	$	(0.47	)	$	1.97		$	3.27
Units used to compute net (loss) income per limited partner unit:
Common - basic		10,999,848			10,091,388			10,947,890			10,081,840
Common - diluted		10,999,848			10,091,388			11,174,910			10,084,821
Subordinated - basic and diluted		10,071,970			10,071,970			10,071,970			10,071,970
Distribution declared per common and subordinated units	$	0.4875		$	0.4275		$	0.9600		$	0.8400

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

Sprague Resources LP

Unaudited Condensed Consolidated Statements of Comprehensive (Loss) Income

(in thousands)


	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
Net (loss) income	$	(2,550	)	$	(10,604	)	$	41,389		$	62,528
Other comprehensive (loss) income, net of tax:
Unrealized (loss) gain on interest rate swaps
Net loss arising in the period		(260	)		(36	)		(960	)		(99	)
Reclassification adjustment related for losses realized in income		128			625			258			1,233

Net change in unrealized loss (gain) on interest rate swaps		(132	)		589			(702	)		1,134
Tax effect		4			(15	)		21			(29	)

		(128	)		574			(681	)		1,105
Foreign currency translation adjustment		100			456			(1,249	)		(3	)

Other comprehensive (loss) income		(28	)		1,030			(1,930	)		1,102

Comprehensive (loss) income	$	(2,578	)	$	(9,574	)	$	39,459		$	63,630

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

Sprague Resources LP

Unaudited Condensed Consolidated Statements of Unitholders’ Equity (Deficit)

(in thousands)


										Accumulated
				Common-			Subordinated-			Other
	Common-			Sprague			Sprague			Comprehensive
	Public			Holdings			Holdings			(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
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		17,551			4,006			19,832			—			41,389
Other comprehensive loss		—			—			—			(1,930	)		(1,930	)
Unit-based compensation		593			135			670			—			1,398
Distribution to unitholders		(8,288	)		(1,892	)		(9,367	)		—			(19,547	)
Common units issued in connection with annual bonus		2,088			479			2,372			—			4,939
Units withheld for employee tax obligation		(990	)		(227	)		(1,126	)		—			(2,343	)

Balance at June 30, 2015	$	182,009		$	(3,065	)	$	(27,381	)	$	(11,763	)	$	139,800

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

Sprague Resources LP

Unaudited Condensed Consolidated Statements of Cash Flows

(in thousands)


	Six Months Ended June 30,
	2015			2014
Cash flows from operating activities
Net income	$	41,389		$	62,528
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization (includes amortization of deferred debt issue costs)		11,964			10,549
Provision for doubtful accounts		1,063			607
Gain on sale of assets and insurance recoveries		(524	)		(26	)
Deferred income taxes		(388	)		291
Non-cash unit-based compensation		4,132			615
Changes in assets and liabilities:
Accounts receivable		124,251			76,823
Inventories		181,797			211,847
Prepaid expenses and other assets		16,256			6,121
Fair value of commodity derivative instruments		76,101			(45,156	)
Due to General Partner and affiliates		(4,386	)		9,213
Accounts payable, accrued liabilities and other		(141,644	)		(121,743	)

Net cash provided by operating activities		310,011			211,669

Cash flows from investing activities
Purchases of property, plant and equipment		(6,944	)		(11,150	)
Proceeds from property insurance settlement, sale of assets and other activities		310			136

Net cash used in investing activities		(6,634	)		(11,014	)

Cash flows from financing activities
Net payments under credit agreements		(273,407	)		(184,491	)
Payments on capital lease liabilities and term debt		(632	)		(398	)
Payments on long-term terminal obligations		(172	)		(325	)
Debt issue costs		(1,938	)		—
Distribution to unitholders		(19,547	)		(14,023	)
Foreign exchange on capital lease obligations		(133	)		(2	)
Repurchased units withheld for employee tax obligation		(2,343	)		(136	)
Net increase in payable to Parent		—			146

Net cash used in financing activities		(298,172	)		(199,229	)

Effect of exchange rate changes on cash balances held in foreign currencies		(55	)		79

Net change in cash and cash equivalents		5,150			1,505
Cash and cash equivalents, beginning of period		4,080			2,046

Cash and cash equivalents, end of period	$	9,230		$	3,551

Supplemental disclosure of cash flow information
Cash paid for interest	$	12,864		$	13,912
Cash paid for taxes	$	2,695		$	1,852

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 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.

As of June 30, 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 General Partner, which in turn owns a non-economic interest in the Partnership. Sprague Holdings currently holds incentive distribution rights (“IDRs”) that entitle it to receive increasing percentages, up to a maximum of 50%, of the cash the Partnership distributes from distributable cash flow. IDR participation begins once distributions exceed $0.474375 per unit per quarter. The maximum distribution of 50.0% does not include any distributions that Sprague Holdings may receive on any limited partner units that it owns. See Note 12.

Basis of Presentation

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

The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities in the balance sheet and the reported revenues and expenses in the income statement. Actual results could differ from those estimates. Among the estimates made by management are asset valuations, the fair value of derivative assets and liabilities, environmental, and legal obligations.

The 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 consolidated financial statements included herein reflect all normal and recurring adjustments which, in the opinion of management, are necessary for a fair presentation of the Partnership’s consolidated financial position at June 30, 2015 and December 31, 2014 and the consolidated results of operations and cash flows for the three and six months ended June 30, 2015 and 2014, respectively. The unaudited results of operations for the interim periods reported are not necessarily indicative of results to be expected for the full year. Demand for some of the Partnership’s refined petroleum products, specifically heating oil and residual oil for space heating purposes, and to a lesser extent natural gas, are generally higher during the first and fourth quarters of the calendar year which may result in significant fluctuations in the Partnership’s quarterly operating results.

New Accounting Guidance

In July 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standard Update (“ASU”) ASU 2015-11, Simplifying the Measurement of Inventory, which requires that inventory within the scope of the guidance be measured at the lower of cost and net realizable value. The Partnership is currently evaluating the potential impact of this guidance which is effective for fiscal years beginning after December 15, 2016 and interim periods within those fiscal years.

In April 2015, the FASB issued ASU 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 FASB issued ASU 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 June 30, 2015 and December 31, 2014, the Partnership’s unamortized debt issuance costs were $16.0 million and $15.5 million respectively.

In May 2014, the FASB issued ASU 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. In July 2015, the FASB voted to defer the effective date of this guidance, which is now effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The Partnership continues to evaluate both the impact of this new standard on the consolidated financial statements and the transition method it will utilize for adoption.

2. Business Combinations

Kildair

On December 9, 2014, the Partnership indirectly acquired all of the equity interests in Kildair Service Ltd. (“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 outstanding Kildair debt at the date of acquisition), which included $10.0 million in the Partnership’s 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. Limited partners’ interest in net income (loss) as well as the related per unit amounts have not been recast.

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 900,000 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.

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 Partnership expects to finalize the purchase price allocation during 2015.

The following represents the unaudited pro forma consolidated net sales and net income (loss) as if Castle had been included in the unaudited condensed consolidated results of the Partnership for the three and six months ended June 30, 2014.


	Three Months Ended			Six Months Ended
	June 30, 2014			June 30, 2014
Net sales	$	1,098,013		$	3,533,537
Net (loss) income	$	(12,616	)	$	70,423
Limited partners’ interest in net (loss) income	$	(11,506	)	$	73,736
Net (loss) income per limited partner common unit - basic	$	(0.56	)	$	3.62
Net (loss) income per limited partner common unit - diluted	$	(0.56	)	$	3.62

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 related tax effects.

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 assets and liabilities. 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 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 acquired 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 deductible for tax purposes.

3. Accumulated Other Comprehensive Loss, Net of Tax

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


	June 30,			December 31,
	2015			2014
Fair value of interest rate swaps, net of tax	$	(1,087	)	$	(406	)
Cumulative foreign currency translation adjustment		(10,676	)		(9,427	)

Accumulated other comprehensive loss, net of tax	$	(11,763	)	$	(9,833	)

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


	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
Balance - beginning of period	$	(10,776	)	$	(8,743	)	$	(9,427	)	$	(8,284	)
Foreign currency translation adjustment		100			456			(1,249	)		(3	)

Balance - end of period	$	(10,676	)	$	(8,287	)	$	(10,676	)	$	(8,287	)

4. Inventories


	June 30,		December 31,
	2015		2014
Petroleum and related products	$	181,842	$	366,431
Asphalt		25,311		18,357
Natural gas		1,032		3,387
Coal		573		2,380

Inventories	$	208,758	$	390,555

Due to changing market conditions, the Partnership recorded a provision of $2.7 million and $50.5 million as of June 30, 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 Condensed Consolidated Statements of Operations.

5. Debt


	June 30,		December 31,
	2015		2014
Current debt
Credit agreement	$	206,981	$	396,961
Other		225		253

Current debt		207,206		397,214

Long-term debt
Credit agreement		334,419		417,789
Other		422		567

Long-term debt		334,841		418,356

Total debt	$	542,047	$	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 June 30, 2015 and December 31, 2014, working capital facilities borrowings were $229.8 million and $503.2 million, respectively, and outstanding letters of credit were $20.2 million and $120.2 million, respectively. The working capital facilities are subject to borrowing base reporting and as of June 30, 2015 and December 31, 2014, had a borrowing base of $429.1 million and $843.3 million, respectively. As of June 30, 2015, excess availability under the working capital facility was $179.1 million.

Acquisition line borrowings were $311.6 million at both June 30, 2015 and December 31, 2014, respectively. As of June 30, 2015, excess availability under the acquisition facility was $88.4 million.

The weighted average interest rate was 2.9% and 2.8% at June 30, 2015 and December 31, 2014, respectively, The current portion of the credit agreement at June 30, 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 June 30, 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 $21.2 million and $15.0 million for the three months ended June 30, 2015 and 2014, and $53.8 million and $45.1 million for the six months ended June 30, 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 $11.9 million and $16.3 million as of June 30, 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 (defined below).

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 and six months ended June 30, 2015 and 2014 is presented in the table below:


	Three Months Ended						Six Months Ended
	June 30						June 30
	2015			2014			2015			2014
	(in thousands)						(in thousands)
Net sales:
Refined products	$	578,851		$	898,667		$	2,010,696		$	2,743,640
Natural gas		66,558			67,342			213,237			201,682
Materials handling		11,694			8,999			21,878			17,078
Other operations		4,640			4,653			14,290			11,960

Net sales	$	661,743		$	979,661		$	2,260,101		$	2,974,360

Adjusted gross margin(1):
Refined products	$	25,943		$	18,162		$	92,249		$	69,692
Natural gas		1,316			2,666			36,133			38,010
Materials handling		11,688			8,993			21,872			17,070
Other operations		1,641			1,352			4,624			2,688

Adjusted gross margin		40,588			31,173			154,878			127,460
Reconciliation to operating income (loss)(2):
Add: unrealized gain (loss) on inventory(3)		(2,143	)		759			(5,677	)		6,625
Add: unrealized gain (loss) on natural gas transportation contracts(4)		7,239			(6,059	)		4,468			22,068
Operating costs and expenses not allocated to operating segments:
Operating expenses		(17,641	)		(15,358	)		(36,524	)		(32,196	)
Selling, general and administrative		(18,918	)		(11,124	)		(51,299	)		(38,535	)
Depreciation and amortization		(5,185	)		(4,130	)		(10,177	)		(8,085	)

Operating income (loss)		3,940			(4,739	)		55,669			77,337
Other income		—			—			514			—
Interest income		117			167			229			277
Interest expense		(6,459	)		(6,713	)		(14,225	)		(14,729	)
Income tax (provision) benefit		(148	)		681			(798	)		(357	)

Net (loss) income	$	(2,550	)	$	(10,604	)	$	41,389		$	62,528

(1)

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

(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 gains (losses) with respect to the derivatives that are included in net income (loss).

(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 (loss).

The Partnership had no single customer whose revenue was greater than 10% of total net sales for the three and six months ended June 30, 2015 and 2014, respectively. The Partnership’s foreign sales, primarily sales of refined products, asphalt and natural gas to its customers in Canada, were $49.9 million and $83.1 million for the three months ended June 30, 2015 and 2014, and $108.0 million and $175.5 million for the six months ended June 30, 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 June 30, 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

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 Condensed 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 Condensed Consolidated Balance Sheets. Substantially all of the Partnership’s commodity derivative contracts outstanding as of June 30, 2015 will settle prior to December 31, 2016.

The Partnership enters into some master netting arrangements to mitigate credit risk with significant counterparties. Master netting arrangements are standardized contracts that govern all specified transactions with the same counterparty and allow the Partnership to terminate all contracts upon occurrence of certain events, such as counterparty’s default. The Partnership has elected not to offset the fair value of its derivatives, even where these arrangements provide the right to do so.

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

The Partnership determines fair value in accordance with Accounting Standards Codification (“ASC”) 820, “Fair Value Measurements and Disclosures” which established a hierarchy for the inputs used to measure the fair value of financial assets and liabilities based on the source of the input, which generally range from quoted prices for identical instruments in a principal trading market (Level 1) to estimates determined using significant unobservable inputs (Level 3). Multiple inputs may be used to measure fair value, however, the level of fair value is based on the lowest significant input level within this fair value hierarchy.

Details on the methods and assumptions used to determine the fair values are as follows:

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

Fair value measurements based on Level 2 inputs: Measurements that are derived indirectly from observable inputs or from quoted prices from markets that are less liquid. Measurements based on Level 2 inputs include over-the-counter derivative instruments that are priced on an exchange traded curve, but have contractual terms that are not identical to exchange traded contracts. The Partnership utilizes fair value measurements based on Level 2 inputs for its fixed forward contracts, over-the-counter commodity price swaps and interest rate swaps. The Partnership did not have any transfers between Level 1 and Level 2 fair value measurement during the three and six months ended June 30, 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 June 30, 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 June 30, 2015 and December 31, 2014:


	As of June 30, 2015
			Quoted		Significant
			Prices in		Other		Significant
			Active		Observable		Unobservable
	Fair Value		Markets		Inputs		Inputs
	Measurement		Level 1		Level 2		Level 3
Financial assets:
Commodity exchange contracts	$	18	$	18	$	—	$	—
Commodity fixed forwards		134,076		—		134,076		—
Commodity swaps and options		67		—		67		—

Commodity derivatives		134,161		18		134,143		—
Interest rate swaps		13		—		13		—
Currency swaps		47		—		47		—

Total	$	134,221	$	18	$	134,203	$	—

Financial liabilities:
Commodity exchange contracts	$	2	$	2	$	—	$	—
Commodity fixed forwards		64,346		—		64,346		—
Commodity swaps and options		4,830		—		4,830		—

Commodity derivatives		69,178		2		69,176		—
Interest rate swaps		1,131		—		1,131		—

Total	$	70,309	$	2	$	70,307	$	—


	As of December 31, 2014
			Quoted		Significant
			Prices in		Other		Significant
			Active		Observable		Unobservable
	Fair Value		Markets		Inputs		Inputs
	Measurement		Level 1		Level 2		Level 3
Financial assets:
Commodity 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 Condensed Consolidated Balance Sheets. The maximum amount of loss due to credit risk that the Partnership would incur if its counterparties failed completely to perform according to the terms of the contracts, based on the gross fair value of these financial instruments, was $134.2 million at June 30, 2015. Information related to these offsetting arrangements as of June 30, 2015 and December 31, 2014 is as follows:


	As of June 30, 2015
									Gross Amount Not Offset in
	Gross								the Balance Sheet
	Amounts of			Gross		Amounts of
	Recognized			Amounts		Assets/						Cash
	Assets/			Offset in the		Liabilities in			Financial			Collateral
	Liabilities			Balance Sheet		Balance Sheet			Instruments			Posted			Net Amount
Commodity derivative assets	$	134,161		$	—	$	134,161		$	(3,588	)	$	(310	)	$	130,263
Interest rate swap derivative assets		13			—		13			—			—			13
Currency swap derivative assets		47			—		47			—			—			47

Fair value of derivative assets	$	134,221		$	—	$	134,221		$	(3,588	)	$	(310	)	$	130,323

Commodity derivative liabilities	$	(69,178	)	$	—	$	(69,178	)	$	3,588		$	—		$	(65,590	)
Interest rate swap derivative liabilities		(1,131	)		—		(1,131	)		—			—			(1,131	)

Fair value of derivative liabilities	$	(70,309	)	$	—	$	(70,309	)	$	3,588		$	—		$	(66,721	)


	As of December 31, 2014
									Gross Amount Not Offset in
	Gross								the Balance Sheet
	Amounts of			Gross		Amounts of
	Recognized			Amounts		Assets/						Cash
	Assets/			Offset in the		Liabilities in			Financial			Collateral
	Liabilities			Balance Sheet		Balance Sheet			Instruments			Posted			Net Amount
Commodity derivative assets	$	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 and six months ended June 30, 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 June 30,						Six Months Ended June 30,
	2015			2014			2015		2014
Refined products contracts	$	(35,199	)	$	(3,095	)	$	26,605	$	3,247
Natural gas contracts		5,489			(9,121	)		1,161		(22,814	)

Total	$	(29,710	)	$	(12,216	)	$	27,766	$	(19,567	)

There were no discretionary trading activities for the three and six months ended June 30, 2015 and 2014. The following table presents the gross volume of commodity derivative instruments outstanding as of June 30, 2015 and December 31, 2014:


	As of June 30, 2015						As of December 31, 2014
	Refined Products			Natural Gas			Refined Products			Natural Gas
	(Barrels)			(MMBTUs)			(Barrels)			(MMBTUs)
Long contracts		7,649			117,814			10,823			131,376
Short contracts		(9,800	)		(73,016	)		(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 June 30, 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 six interest rate swaps with a total notional value of $175.0 million whose swap periods begin in January 2016, expiring in January 2017. There was no material ineffectiveness determined for the cash flow hedges for the three and six months ended June 30, 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 June 30, 2015, the amount of unrealized losses, net of tax, expected to be reclassified to earnings during the following twelve-month period was approximately $0.8 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 June 30, 2015, Kildair held a series of forward currency swaps that mature through July 2015. The contracts obligate Kildair to sell $11.5 million in Canadian dollars at an exchange rate of 1.2426 to 1. The Canadian to U.S. dollar exchange rate was 1.2490 to 1 at June 30, 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. Approximately $4.9 million of the annual bonus expense accrual as of December 31, 2014 was subsequently settled by issuing 200,775 common units and the Partnership withheld from the recipients 67,141 common units (market value of $1.7 million) to satisfy minimum tax withholding obligations. The Partnership estimates that $2.7 million of the annual bonus expense recorded during the six months ended June 30, 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 (vested market value of $1.8 million) were issued during January 2015. In connection with these vested awards, the Partnership withheld from the recipients 24,605 units (vested market value of $0.6 million) to satisfy minimum tax withholding obligations.

Total unrecognized compensation cost related to performance-based phantom units totaled $5.0 million as of June 30, 2015, which is expected to be recognized over a period of 30 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 six months ended June 30, 2015 is set forth below:


					Time Based						Performance-Based
	Restricted Units				Phantom Units						Phantom Units
			Weighted					Weighted					Weighted
			Average					Average					Average
			Grant Date					Grant Date					Grant Date
			Fair Value					Fair Value					Fair Value
	Units		(per unit)		Units			(per unit)			Units		(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 June 30, 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
			Sprague		Subordinated
	Public		Holdings		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 June 30, 2015		8,969,914		2,034,378		10,071,970

Unit-based compensation recorded in unitholders’ equity for the three months ended June 30, 2015 and 2014 was $0.6 million and $0.1 million, respectively, and for the six months ended June 30, 2015 and 2014 was $1.4 million and $0.6 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 (loss), after deducting any incentive distributions, by the weighted-average number of outstanding common and subordinated units. The Partnership’s net income is allocated to the limited partners in accordance with their respective 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 (loss) allocations used in the calculation of earnings (loss) 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 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 and six months ended June 30, 2015 and 2014:


	Three Months Ended				Six Months Ended
	June 30				June 30
	2015		2014		2015		2014
Weighted average limited partner common units - basic		10,999,848		10,091,388		10,947,890		10,081,840
Dilutive effect of unvested restricted and phantom units		—		—		227,020		2,981

Weighted average limited partner common units - dilutive		10,999,848		10,091,388		11,174,910		10,084,821

The following tables provides a reconciliation of net income and the assumed allocation of net income to the limited partners’ interest for purposes of computing net income per unit for the three and six months ended June 30, 2015 and 2014:


	Three Months Ended June 30, 2015
	Common			Subordinated			IDR		Total
	(in thousands, except for per unit amounts)
Net loss									$	(2,550	)

Distributions declared	$	5,365		$	4,910		$	49	$	10,324
Assumed net loss from operations after distributions		(6,722	)		(6,152	)		—		(12,874	)

Assumed net (loss) income to be allocated	$	(1,357	)	$	(1,242	)	$	49	$	(2,550	)

Loss per unit - basic	$	(0.12	)	$	(0.12	)
Loss per unit - diluted	$	(0.12	)	$	(0.12	)

	Three Months Ended June 30, 2014
	Common			Subordinated			IDR		Total
	(in thousands, except for per unit amounts)
Net loss									$	(10,604	)
Loss attributable to Kildair (Note 2)										1,110

									$	(9,494	)

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

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

Loss per unit - basic	$	(0.47	)	$	(0.47	)
Loss per unit - diluted	$	(0.47	)	$	(0.47	)

	Six Months Ended June 30, 2015
	Common			Subordinated			IDR		Total
	(in thousands, except for per unit amounts)
Net income									$	41,389

Distributions declared	$	10,569		$	9,669		$	49	$	20,287
Assumed net income from operations after distributions		10,962			10,140			—		21,102

Assumed net income to be allocated	$	21,531		$	19,809		$	49	$	41,389

Earnings per unit - basic	$	1.97		$	1.97
Earnings per unit - diluted	$	1.93		$	1.97

	Six Months Ended June 30, 2014
	Common			Subordinated			IDR		Total
	(in thousands, except for per unit amounts)
Net income									$	62,528
Loss attributable to Kildair (Note 2)										3,313

									$	65,841

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

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

Earnings per unit - basic	$	3.27		$	3.27
Earnings per unit - diluted	$	3.27		$	3.27

12. Partnership Distributions

The Partnership agreement sets forth the calculation to be used to determine the amount and priority of cash distributions that the common and subordinated unitholders will receive. As holder of the IDRs, Sprague Holdings is entitled to incentive distributions if the amount that the Partnership distributes exceeds specified target levels shown below:


		Marginal Percentage Interest in
		Cash Distributions
					Incentive
	Quarterly Distribution per				Distribution
	Unit Target Amount	Unitholders			Rights Holders
Minimum Quarterly Distribution	$0.4125		100.0	%		0	%
First Target Distribution	above $0.4125 up to $0.474375		100.0	%		0	%
Second Target Distribution	above $0.474375 up to $0.515625		85.0	%		15.0	%
Third Target Distribution	above $0.515625 up to $0.61875		75.0	%		25.0	%
Thereafter	above $0.61875		50.0	%		50.0	%

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

On April 29, 2015, the Partnership declared a cash distribution of $0.4725 per unit for the three months ended March 31, 2015, which was paid on May 15, 2015, to unitholders of record on May 11, 2015.

13. Subsequent Event

On July 29, 2015, the Partnership declared a cash distribution for the three months ended June 30, 2015, of $0.4875 per unit, to unitholders of record on August 10, 2015, to be paid on August 14, 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 June 30, 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:

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

Any disruptions in our labor force could unfavorably impact our business.

•

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

•

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

•

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

•

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

•

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

•

The condition of credit markets may adversely affect us.

•

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

•

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

•

The other risks set forth in our Annual Report on Form 10-K for the year ended December 31, 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”, or like terms when used in a historical context prior to October 30, 2013, the date on which the Partnership completed the initial public offering of its common units representing limited partner 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 and six months ended June 30, 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. “Condensed Consolidated Financial Statements” of this Quarterly Report.

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 1.8 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 approximately 60 third-party terminals in the Northeast United States through which we sell or distribute refined products pursuant to rack, exchange and throughput agreements.

As of June 30, 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 General Partner, which in turn owns a non-economic interest in the Partnership. Sprague Holdings currently holds the incentive distribution rights (“IDRs”) which entitle it to receive increasing percentages, up to a maximum of 50%, of the cash the Partnership distributes from distributable cash flow in excess of $0.474375 per unit per quarter. The maximum distribution of 50.0% does not include any distributions that Sprague Holdings may receive on any limited partner units that it owns.

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.”

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 June 30, 2015 and 2014, we sold 289.1 million and 306.1 million gallons of refined products, respectively, and our refined products segment accounted for 64% and 58% of our adjusted gross margin, respectively. For the six months ended June, 2015 and 2014, we sold 1.0 billion and 0.9 billion gallons of refined products, respectively, and our refined products segment accounted for 60% and 55% 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 June 30, 2015 and 2014, we sold 12.2 Bcf and 11.5 Bcf of natural gas, respectively, which accounted for 3% and 9% of our adjusted gross margin, respectively. For the six months ended June 30, 2015 and 2014, we sold 32.2 Bcf and 28.0 Bcf of natural gas, respectively, which accounted for 23% and 30% 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 June 30, 2015, we offloaded, stored and/or prepared for delivery 0.5 million short tons of products and 50.0 million gallons of liquid materials. For the three months ended June 30, 2014, we offloaded, stored and/or prepared for delivery 0.5 million short tons of products and 45.4 million gallons of liquid materials. For the three months ended June 30, 2015 and 2014, our materials handling segment accounted for 29% of our adjusted gross margin for both periods. For the six months ended June 30, 2015, we offloaded, stored and/or prepared for delivery 1.1 million short tons of products and 124.7 million gallons of liquid materials. For the six months ended June 30, 2014, we offloaded, stored and/or prepared for delivery 1.2 million short tons of products and 112.2 million gallons of liquid materials. For the six months ended June 30, 2015 and 2014, our materials handling segment accounted for 14% and 13% of our adjusted gross margin respectively.

Our other operations segment includes the marketing and distribution of coal conducted in our Portland, Maine terminal, commercial trucking activity conducted by our Canadian subsidiary and the heating equipment service business acquired with the Castle acquisition in December 2014. For the three months ended June 30, 2015 and 2014, our other operations segment accounted for 4% of our adjusted gross margin for both periods. For the six months ended June 30, 2015 and 2014, our other operations segment accounted for 3% and 2% of our adjusted gross margin, respectively.

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

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:

•

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

•

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

•

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

•

The viability of acquisitions and capital expenditure projects.

EBITDA is not prepared in accordance with GAAP. EBITDA should not be considered an alternative to net income (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 (loss).

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:

•

The economic results of our operations;

•

The market value of our inventory and natural gas transportation contracts for financial reporting to our lenders, as well as for borrowing base purposes; and

•

Repeatable operating performance that is not distorted by non-recurring items or market volatility.

Adjusted gross margin 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), operating income (loss), 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 and six months ended June 30, 2014 have been recast to include the historical results of Kildair Service Ltd (“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 and six months ended June 30, 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

In addition to the other information set forth in this report, please refer to our Annual Report on Form 10-K for the fiscal year ended December 31, 2014 for a discussion of the trends and factors that impact our business.

Qualifying Income Status and Proposed Regulations

Pursuant to Internal Revenue Code Section 7704(c)(2), in order to be treated as a partnership for U.S. federal income tax purposes, more than 90 percent of the income of a partnership must be from certain specified sources, including the exploration, development, mining or production, processing, refining, transportation and marketing of minerals and natural resources. On May 5, 2015, the Treasury Department and the IRS issued the Proposed Regulations regarding qualifying income under Section 7704(d)(1)(E) of the Code. The Proposed Regulations provide rules regarding the Qualifying Income Exception. The comment period on the proposed new regulations ends on August 5, 2015. When the comment period closes, the IRS will review and analyze the comments received. During this time, they may consult with industry experts and others to fully understand the matter. However, there is no set time frame for this process and it can take months or years to finalize the proposed new regulations. Although we do not believe, based upon our current operations and language of the proposed regulations, that we will be treated as a corporation for U.S. federal income tax purposes, finalized regulations could modify the amount of our gross income that we are able to treat as qualifying income for purposes of the qualifying income requirement and modify or revoke existing private letter rulings, including ours.

Results of Operations

On December 9, 2014, we acquired Kildair. The acquisition of Kildair 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. In December, 2014 we expanded our refined products business through our acquisition of Castle Oil Corporation (“Castle Oil”) and in October, 2014 we expanded our natural gas business through our acquisition of Metromedia Gas & Power, Inc. (“Metromedia Energy”). Our current and future results of operations may not be comparable to our historical results of operations for the periods presented due to business combinations.

The results of operations of our refined products and natural gas businesses are impacted by seasonality, due primarily to the increase in volumes sold during the peak heating season from October through March. In addition, product price fluctuations can have a significant impact on our revenues. For these and other reasons, our results of operations for the three and six months ended June 30, 2015 are not necessarily indicative of the results to be expected for future periods or for the full fiscal year ending December 31, 2015.

The following tables present our volume, net sales, and adjusted gross margin by segment, as well as our EBITDA, adjusted EBITDA, and information on weather conditions, for the three and six months ended June 30, 2015 and 2014:


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2015			2014			2015			2014
	(in thousands)						(in thousands)
Volumes:
Refined products (gallons)		289,086			306,096			1,015,518			894,852
Natural gas (MMBtus)		12,218			11,493			32,231			27,989
Materials handling (short tons)		484			525			1,069			1,219
Materials handling (gallons)		49,980			45,360			124,740			112,182
Net Sales:
Refined products	$	578,851		$	898,667		$	2,010,696		$	2,743,640
Natural gas		66,558			67,342			213,237			201,682
Materials handling		11,694			8,999			21,878			17,078
Other operations		4,640			4,653			14,290			11,960

Total net sales	$	661,743		$	979,661		$	2,260,101		$	2,974,360

Adjusted Gross Margin:
Refined products	$	25,943		$	18,162		$	92,249		$	69,692
Natural gas		1,316			2,666			36,133			38,010
Materials handling		11,688			8,993			21,872			17,070
Other operations		1,641			1,352			4,624			2,688

Total adjusted gross margin	$	40,588		$	31,173		$	154,878		$	127,460

Reconciliation to Operating Income (loss):
Total adjusted gross margin	$	40,588		$	31,173		$	154,878		$	127,460
Add: unrealized gain (loss) on inventory (1)		(2,143	)		759			(5,677	)		6,625
Add: unrealized gain (loss) on natural gas transportation contracts (2)		7,239			(6,059	)		4,468			22,068
Operating expenses		(17,641	)		(15,358	)		(36,524	)		(32,196	)
Selling, general and administrative		(18,918	)		(11,124	)		(51,299	)		(38,535	)
Depreciation and amortization		(5,185	)		(4,130	)		(10,177	)		(8,085	)

Operating income (loss)	$	3,940		$	(4,739	)	$	55,669		$	77,337
Other income		—			—			514			—
Interest income		117			167			229			277
Interest expense		(6,459	)		(6,713	)		(14,225	)		(14,729	)
Income tax (provision) benefit		(148	)		681			(798	)		(357	)

Net (loss) income	$	(2,550	)	$	(10,604	)	$	41,389		$	62,528


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2015			2014			2015			2014
	(in thousands)						(in thousands)
Reconciliation of Net Income to Adjusted EBITDA
Net (loss) income	$	(2,550	)	$	(10,604	)	$	41,389		$	62,528
Add/(deduct):
Interest expense, net		6,342			6,546			13,996			14,452
Tax provision (benefit)		148			(681	)		798			357
Depreciation and amortization		5,185			4,130			10,177			8,085

EBITDA (3):	$	9,125		$	(609	)	$	66,360		$	85,422

Add: unrealized (gain) loss on inventory (1)		2,143			(759	)		5,677			(6,625	)
Add: unrealized (gain) loss on natural gas transportation contracts (2)		(7,239	)		6,059			(4,468	)		(22,068	)

Adjusted EBITDA (3):	$	4,029		$	4,691		$	67,569		$	56,729

Other Data:
Normal heating degree days (4)		954			954			4,228			4,228
Actual heating degree days		884			935			4,765			4,541
Variance from normal heating degree days		(7.3	)%		(2.0	)%		12.7	%		7.4	%
Variance from prior period actual heating degree days		(5.5	)%		0.6	%		4.9	%		11.4	%

(1)

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 (loss).

(2)

(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 June 30, 2015 compared to Three Months Ended June 30, 2014

Our results of operations for the three months ended June 30, 2015 reflect:

•

decreasing net sales and sales volumes and increasing adjusted gross margin and adjusted unit gross margin in our refined products segment;

•

decreasing net sales, increasing sales volumes and decreasing adjusted gross margin and adjusted unit gross margin in our natural gas segment; and

•

increasing net sales and adjusted gross margin in our materials handling segment.


	Three Months Ended
	June 30,				Increase/(Decrease)
	2015		2014		$			%
	($ in thousands, except adjusted unit gross margin)
Volumes:
Refined products (gallons)		289,086		306,096		(17,010	)		(6	)%
Natural gas (MMBtus)		12,218		11,493		725			6	%
Materials handling (short tons)		484		525		(41	)		(8	)%
Materials handling (gallons)		49,980		45,360		4,620			10	%
Net Sales:
Refined products	$	578,851	$	898,667	$	(319,816	)		(36	)%
Natural gas		66,558		67,342		(784	)		(1	)%
Materials handling		11,694		8,999		2,695			30	%
Other operations		4,640		4,653		(13	)		(0	)%

Total net sales	$	661,743	$	979,661	$	(317,918	)		(32	)%

Adjusted Gross Margin:
Refined products	$	25,943	$	18,162	$	7,781			43	%
Natural gas		1,316		2,666		(1,350	)		(51	)%
Materials handling		11,688		8,993		2,695			30	%
Other operations		1,641		1,352		289			21	%

Total adjusted gross margin	$	40,588	$	31,173	$	9,415			30	%

Adjusted Unit Gross Margin:
Refined products	$	0.090	$	0.059	$	0.031			53	%
Natural gas	$	0.108	$	0.232	$	(0.124	)		(53	)%

Refined Products

Refined products net sales decreased $319.8 million, primarily as a result of the lower energy price environment. The average selling price for the three months ended June 30, 2015 was nearly 32% lower than the same period last year.

Refined products sales volumes during the quarter were 17.0 million gallons or 6% lower, which contributed to the decline in sales. A reduction of 21.0 million gallons in residual fuel volumes was the primary contributor to this decrease, with gasoline sales volume also lower. The key driver for the residual fuel decline was reduced export volumes at Kildair. In contrast to residual fuel and gasoline, distillate sales volumes increased during the period, which was largely attributable to the recently acquired Castle business.

Refined products adjusted gross margin increased $7.8 million due to the contribution from our Castle acquisition, improved margin performance in Kildair’s refined product business and a more favorable market structure for holding inventory, in particular for residual fuel and distillate.

Natural Gas

Natural gas net sales decreased $0.8 million or 1%. This decline was driven by the lower energy price environment, with the average selling price 7% lower, while volumes increased due to the Metromedia Energy acquisition completed in October 2014.

Natural Gas adjusted gross margin declined by $1.4 million compared to the same period last year. Adjusted gross margin gains from increasing sales volumes were offset by a combination of widening credit spreads on forward contracts, fewer optimization opportunities for our transportation and storage assets and reduced weather-driven requirements.

Materials Handling

Materials handling net sales increased $2.7 million primarily as a result of an increase in windmill handling activity following the reinstatement of the Renewable Electricity Production Tax Credit and higher revenue from Kildair’s crude handling project, which started up during the latter part of the second quarter of 2014. This increase was offset by lower dry bulk activity due to a temporary customer plant shutdown and reduced salt demand following an exceptional year in 2014.

Materials handling adjusted gross margin improvement of $2.7 million was primarily a combination of substantially higher windmill activity and a full quarter of crude handling revenue at Kildair. Asphalt revenue also increased, largely as a result of activity at the Bronx, NY terminal, which was obtained as part of the Castle acquisition in December 2014. Dry bulk adjusted gross margin was lower for the second quarter of 2015, largely as a result of a customer’s temporary plant shutdown and lower salt volumes.

Other Operations

Net sales from other operations were relatively unchanged from the same period last year with reductions in coal demand and commercial trucking services at Kildair offsetting the gains in heating equipment service sales obtained as part of the Castle acquisition.

Adjusted gross margins from other operations increased $0.3 million as a result of sales in the heating equipment service business described above.

Six Months Ended June 30, 2015 compared to Six Months Ended June 30, 2014

Our results of operations for the six months ended June 30, 2015 reflect:

•

decreasing net sales and increasing sales volumes, adjusted gross margin and adjusted unit gross margin in our refined products segment;

•

increasing net sales, sales volumes and decreasing adjusted gross margin and adjusted unit gross margin in our natural gas segment; and

•

increasing net sales and adjusted gross margin in our materials handling segment.


	Six Months Ended
	June 30,				Increase/(Decrease)
	2015		2014		$			%
	($ in thousands, except adjusted unit gross margin)
Volumes:
Refined products (gallons)		1,015,518		894,852		120,666			13	%
Natural gas (MMBtus)		32,231		27,989		4,242			15	%
Materials handling (short tons)		1,069		1,219		(150	)		(12	)%
Materials handling (gallons)		124,740		112,182		12,558			11	%
Net Sales:
Refined products	$	2,010,696	$	2,743,640	$	(732,944	)		(27	)%
Natural gas		213,237		201,682		11,555			6	%
Materials handling		21,878		17,078		4,800			28	%
Other operations		14,290		11,960		2,330			19	%

Total net sales	$	2,260,101	$	2,974,360	$	(714,259	)		(24	)%

Adjusted Gross Margin:
Refined products	$	92,249	$	69,692	$	22,557			32	%
Natural gas		36,133		38,010		(1,877	)		(5	)%
Materials handling		21,872		17,070		4,802			28	%
Other operations		4,624		2,688		1,936			72	%

Total adjusted gross margin	$	154,878	$	127,460	$	27,418			22	%

Adjusted Unit Gross Margin:
Refined products	$	0.091	$	0.078	$	0.013			17	%
Natural gas	$	1.121	$	1.358	$	(0.237	)		(17	)%

Refined Products

Refined products net sales decreased $732.9 million as a result of the lower energy price environment, with the average refined products sales price per unit during the first six months of 2015 more than 35% lower than the same period in 2014. This price decline was more than offset by higher sales volumes.

Refined products sales volumes increased 120.7 million gallons. The majority of this increase was due to higher distillate sales, with volumes increasing by 101.5 million gallons, or 15%, period over period. This increase was largely a result of higher heating oil volumes, particularly due to sales at the Bronx, NY terminal which was acquired from Castle in December 2014. Colder weather during the first three months of 2015 was also a factor contributing to the higher heating oil volumes. Residual fuel sales volumes also increased by 18.9 million gallons, primarily due to the addition of volumes sold from the Bronx, NY terminal following the Castle acquisition. Gasoline sales volumes were comparable to the same period in 2014.

Refined products adjusted gross margin increased $22.6 million, or 32%. This increase was substantially due to both higher volumes and improved unit margins. As described above, volume increases were largely a result of the Castle acquisition in December 2014 and colder weather conditions during the first quarter of the year. A key factor leading to the higher unit margin was a more favorable market structure for holding inventory which occurred during the second quarter of the year, in particular for residual fuel oil and distillate.

Natural Gas

Natural gas net sales increased $11.6 million, primarily due to a 15% gain in volumes. The key factor leading to the higher volumes was the incremental sales in the first half of 2015 resulting from the Metromedia Energy acquisition completed in October 2014. This volume gain was partially offset by an 8% reduction in natural gas sales prices due to a generally weaker energy price environment as compared to the six months ended June 30, 2014.

Adjusted gross margin declined $1.9 million. 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 as compared to the six months ended June 30, 2014.

Materials Handling

Materials handling net sales increased $4.8 million due to an increase in windmill handling activity following the reinstatement of the Renewable Electricity Production Tax Credit and substantially higher revenue from Kildair’s crude handling project which started up during the latter part of the second quarter of 2014, and the inclusion of asphalt handling revenue at the Bronx, NY terminal purchased from Castle in December 2014. These increases were offset by lower dry bulk activity due to a temporary customer plant shutdown and reduced salt volumes following an exceptional year in 2014.

The primary factors contributing to the materials handling adjusted gross margin increase of $4.8 million were the same as those leading to the revenue increase described above. There were substantial gains from windmill handling activity, crude oil handling at Kildair, and asphalt at the Bronx, NY facility, with a partial offset from lower dry bulk margins in particular due to a temporary customer plant shutdown and reduced salt volumes.

Other Operations

Net sales from other operations increased $2.3 million. The higher sales obtained were primarily due to inclusion of the heating equipment service business obtained as part of the Castle acquisition in December 2014 along with increased coal volumes due mainly to higher demand for power generation during the first quarter.

Adjusted gross margins from other operations increased $1.9 million, with the improvement driven by the same factors as the sales increase.

Operating Costs and Expenses

Three Months Ended June 30, 2015 compared to Three Months Ended June 30, 2014


	Three Months Ended June 30,				Increase/(Decrease)
	2015		2014		$			%
			($ in thousands)
Operating expenses	$	17,641	$	15,358	$	2,283		15%
Selling, general and administrative expenses	$	18,918	$	11,124	$	7,794		70%
Depreciation and amortization	$	5,185	$	4,130	$	1,055		26%
Interest expense, net	$	6,342	$	6,546	$	(204	)	(3)%

Operating Expenses. Operating expenses increased $2.3 million largely due to expenses at our recently acquired Castle terminal.

Selling, General and Administrative Expenses. Selling, general and administrative expenses increased $7.8 million, consisting of $4.0 million attributable to expenses at Metromedia Energy and Castle Oil, $1.2 million due to increased employee related costs, $1.4 million due to increased professional services including audit related, legal and consulting activities and $0.5 million of merger and acquisition expenses.

Depreciation and Amortization. Depreciation and amortization increased $1.1 million, of which $0.9 million was due to the Metromedia Energy and Castle acquisitions.

Interest Expense, net. Interest expense decreased $0.2 million, primarily due to the expiration of interest rate swaps related to a portion of our variable rate debt obligations offset by increased amortization of debt issuance costs associated with our credit facility.

Six Months Ended June 30, 2015 compared to Six Months Ended June 30, 2014


	Six Months Ended June 30,				Increase/(Decrease)
	2015		2014		$			%
			($ in thousands)
Operating expenses	$	36,524	$	32,196	$	4,328		13%
Selling, general and administrative expenses	$	51,299	$	38,535	$	12,764		33%
Depreciation and amortization	$	10,177	$	8,085	$	2,092		26%
Interest expense, net	$	13,996	$	14,452	$	(456	)	(3)%

Operating Expenses. Operating expenses increased $4.3 million, of which $4.6 million was due to expenses at our recently acquired Castle terminal partially offset by $0.4 million in reduced maintenance expense at our other terminals.

Selling, General and Administrative Expenses. Selling, general and administrative expenses increased $12.8 million, of which $8.2 million was attributable to the Metromedia Energy and Castle acquisitions, $1.2 million was due to increased employee related costs, $1.7 million was due to increased professional fees and $1.4 million was due to increased merger and acquisition expense.

Depreciation and Amortization. Depreciation and amortization increased $2.1 million, of which $1.6 million was due to the Metromedia Energy and Castle acquisitions with the remaining increase of $0.5 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. Interest expense decreased $0.5 million, primarily due to the expiration of interest rate swaps related to a portion of our variable rate debt obligations offset by increased amortization of debt issuance costs associated with our 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 June 30, 2015, the Partnership had working capital of $149.7 million.

As of June 30, 2015, the undrawn borrowing capacity under the working capital facility was $179.1 million and the undrawn borrowing capacity under the acquisition facility was $88.4 million. 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 six months ended June 30, 2015, the amount the Partnership had drawn under the working capital facility fluctuated from a low of $215.0 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. The Credit Agreement matures on December 9, 2019 and contains, among other items, the following:

•

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

•

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

•

A revolving acquisition facility of up to $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.

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

The Credit Agreement contains various covenants and restrictive provisions that, among other things, prohibit the Partnership from making distributions to unitholders if any event of default occurs or would result from the distribution or if the Partnership would not be in pro forma compliance with its financial covenants after giving effect to the distribution. In addition, the Credit Agreement contains various covenants that are usual and customary for a financing of this type, size and purpose, including, among others: to maintain a minimum consolidated EBITDA-to-fixed charge ratio, a minimum consolidated Net Working Capital amount, a maximum consolidated total leverage-to-EBITDA ratio, a maximum consolidated senior secured leverage-to-EBITDA ratio. The Credit Agreement also limits our ability to incur debt, grant liens, make certain investments or acquisitions, dispose of assets, and incur additional indebtedness. The Partnership was in compliance with the covenants under the Credit Agreement at June 30, 2015.

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 six months ended June 30, 2015, we incurred a total of $4.4 million in maintenance capital expenditures and we spent $2.5 million for expansion and/or upgrades of our terminals. We anticipate that future maintenance capital expenditures will be funded with our acquisition line and that future expansion capital requirements will be financed through our acquisition line or other long-term borrowings and/or equity offerings.

Cash Flows


	Six Months Ended June 30,
	2015			2014
	($ in thousands)
Net cash provided by operating activities	$	310,011		$	211,669
Net cash used in investing activities	$	(6,634	)	$	(11,014	)
Net cash used in financing activities	$	(298,172	)	$	(199,229	)

Operating Activities

Net cash provided by operating activities for the six months ended June 30, 2015 was $310.0 million. This was primarily driven by cash inflows as a result of a decrease of $181.8 million in inventories due to strong sales volumes and a seasonal reduction in inventory requirements, a decrease of $124.3 million in accounts receivable relating largely to the exit from the winter season, a decrease of $76.1 million in derivative instruments relating to the ratable liquidation of the Partnership’s fixed forward contracts as we came out of the peak season and $41.4 million in net income. These increases were offset by cash outflows as a result of a reduction of $141.6 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 six months ended June 30, 2014 was $211.7 million. This was primarily driven by cash inflows as a result of a decrease of $211.8 million in inventory and $76.8 million in accounts receivable, as levels normally decrease as we exit the winter season, and net income of $62.5 million. These increases were offset by cash outflows as a result of reductions in accounts payable and accrued liabilities of $121.7 million, primarily due to timing of invoice payments for product purchases as we exit the winter season, as well as an increase of $45.2 million in derivative instruments primarily relating to natural gas fixed forward net commitments during the period.

Investing Activities

Net cash used in investing activities for the six months ended June 30, 2015 was $6.6 million of which $2.5 million related to expansion capital expenditures and $4.4 million related to maintenance capital expenditure projects across our terminal system. This was offset by $0.3 million of other activities.

Net cash used in investing activities for the six months ended June 30, 2014 was $11.0 million of which $8.8 million related to expansion capital expenditure projects at our Kildair terminal for a crude oil storage and handling construction project and $2.0 million related to other capital projects across our terminal system.

Financing Activities

Net cash used in financing activities for the six months ended June 30, 2015 was $298.2 million, and primarily resulted from $273.4 million of net payments under our Credit Agreement due to reduced financing requirements from lower inventory levels and lower commodity prices and distributions to unitholders of $19.5 million.

Net cash used in financing activities for the six months ended June 30, 2014 was $199.2 million and primarily resulted from $184.5 million of net payments under the Credit Agreement due to reduced financing needs primarily as a result of lower inventory and accounts receivable levels, and distributions to unitholders of $14.0 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 and six months ended June 30, 2015 and 2014.

New Accounting Guidance

Our policies on new accounting guidance are summarized in Note 1, “Description of Business and Summary of Significant Accounting Policies” in this report and included within the Notes to our Consolidated and Combined Financial Statements of our Annual Report on Form 10-K for the fiscal year ended December 31, 2014.

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 condensed consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of these condensed consolidated financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the condensed consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results may differ from these estimates under different assumptions or conditions.

These estimates are based on our knowledge and understanding of current conditions and actions that we may take in the future. Changes in these estimates will occur as a result of the passage of time and the occurrence of future events. Subsequent changes in these estimates may have a significant impact on our financial condition and results of operations and are recorded in the period in which they become known. We have identified the following estimates that, in our opinion, are subjective in nature, require the exercise of judgment and involve complex analysis: asset valuations, the fair value of derivative assets and liabilities, environmental and legal obligations.

The significant accounting policies and estimates that have been adopted and followed in the preparation of our consolidated financial statements are detailed in Note 1—“Description of Business and Summary of Significant Accounting Policies” included in our 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 (exclusive of depreciation and amortization) for the three and six months ended June 30, 2015 and 2014:


	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015		2014
Refined products contracts	$	(35,199	)	$	(3,095	)	$	26,605	$	3,247
Natural gas contracts		5,489			(9,121	)		1,161		(22,814	)

Total	$	(29,710	)	$	(12,216	)	$	27,766	$	(19,567	)

Substantially all of our commodity derivative contracts outstanding as of June 30, 2015 will settle prior to December 31, 2016.

Interest Rate Risk

We enter into interest rate swaps to manage exposures in changing interest rates. We swap the variable LIBOR interest rate payable under our Credit Agreement for fixed LIBOR interest rates. These interest rate swaps meet the criteria to receive cash flow hedge accounting treatment. Counterparties to our interest rate swaps are large multi-national banks and we do not believe there is a material risk of counterparty nonperformance. At June 30, 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 six interest rate swaps with a total notional value of $175.0 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.

During the two year period ended June 30, 2015, we hedged approximately 25% of our floating rate debt with fixed-for-floating interest rate swaps. We expect to continue to utilize interest rate swaps to manage our exposure to LIBOR interest rates. Based on a sensitivity analysis for the twelve months ended June 30, 2015, it was estimated that if short-term interest rates average 100 basis points higher (lower), interest expense would increase by approximately $4.7 million and decrease by approximately $0.7 million respectively. These amounts were estimated by considering the effect of the hypothetical short-term interest rates on variable-rate debt outstanding, adjusted for interest rate hedges.

Derivative Instruments

The following tables present all of our financial assets and financial liabilities measured at fair value on a recurring basis as of June 30, 2015:


	As of June 30, 2015
			Quoted		Significant
			Prices in		Other		Significant
			Active		Observable		Unobservable
	Fair Value		Markets		Inputs		Inputs
	Measurement		Level 1		Level 2		Level 3
Financial assets:
Commodity exchange contracts	$	18	$	18	$	—	$	—
Commodity fixed forwards		134,076		—		134,076		—
Commodity swaps and options		67		—		67		—

Commodity derivatives		134,161		18		134,143		—
Interest rate swaps		13		—		13		—
Currency swaps		47		—		47		—

Total	$	134,221	$	18	$	134,203	$	—

Financial liabilities:
Commodity exchange contracts	$	2	$	2	$	—	$	—
Commodity fixed forwards		64,346		—		64,346		—
Commodity swaps and options		4,830		—		4,830		—

Commodity derivatives		69,178		2		69,176		—
Interest rate swaps		1,131		—		1,131		—

Total	$	70,309	$	2	$	70,307	$	—

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. Control measures include volumetric, value at risk and stop loss limits on discretionary positions as well as contract term limits. Our Chief Risk Officer and the Risk Management Committee must approve the use of new instruments or new commodities. Risk limits are monitored and reported daily to senior management. Our risk management department also performs independent verifications of sources of fair values. These controls apply to all of our commodity risk management activities.

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

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

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

Item 4.

Controls and Procedures

Disclosure Controls and Procedures

Our management, with the participation of our Chief Executive Officer and our Chief Operating Officer/Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures as of June 30, 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 June 30, 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 and six months ended June 30, 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 factor set forth below, which updates a previously disclosed risk factor, and the factors discussed in “Risk Factors” included in our 2014 Annual Report, which could materially affect our business, financial condition or future results.

The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes or differing interpretations, possibly applied on a retroactive basis.

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units, may be modified by administrative, legislative or judicial changes or differing interpretations at any time. For example, the Fiscal Year 2016 Budget proposed by the President recommends that certain publicly traded partnerships earning income from activities related to fossil fuels be taxed as corporations beginning in 2021. From time to time, members of Congress propose and consider such substantive changes to the existing U.S. federal income tax laws that affect publicly traded partnerships. If successful, the Obama administration’s proposal or other similar proposals could eliminate the qualifying income exception to the treatment of all publicly-traded partnerships as corporations upon which we rely for our treatment as a partnership for U.S. federal income tax purposes.

In addition, the IRS, on May 5, 2015, issued proposed regulations concerning which activities give rise to qualifying income within the meaning of Section 7704 of the Internal Revenue Code. We do not believe the proposed regulations affect our ability to qualify as a publicly traded partnership. However, finalized regulations could modify the amount of our gross income that we are able to treat as qualifying income for the purposes of the qualifying income requirement and modify or revoke existing private letter rulings, including ours.

Any modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

(c)

None.

Item 3.

Defaults Upon Senior Securities

None.

Item 4.

Mine Safety Disclosures

Not applicable.

Item 5.

Other Information

None.

Item 6.

Exhibits

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


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: August 6, 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.