Sprague Resources LP - FORM 10-Q

Attached files

file	filename
EX-31.1 - EX-31.1 - Sprague Resources LP	d621489dex311.htm
EX-31.2 - EX-31.2 - Sprague Resources LP	d621489dex312.htm
EX-32.1 - EX-32.1 - Sprague Resources LP	d621489dex321.htm
EX-32.2 - EX-32.2 - Sprague Resources LP	d621489dex322.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2013

¨	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.)

Two International Drive

Suite 200

Portsmouth, New Hampshire

03801

(Address of principal executive offices)

(Zip Code)

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 ¨ No x

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):

Large accelerated filer ¨

Accelerated filer ¨

Non-accelerated filer x

Smaller reporting company ¨

(Do not check if a smaller

reporting company)

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

As of November 27, 2013, the registrant had approximately 10,078,637 common units and approximately 10,071,970 subordinated units outstanding.

Table of Contents


		Page
PART I - FINANCIAL INFORMATION

Item 1.	Financial Statements:

SPRAGUE RESOURCES LP
	Balance Sheets		3
	Notes to Unaudited Financial Statements		4

SPRAGUE OPERATING RESOURCES LLC
	Consolidated Balance Sheets		7
	Unaudited Consolidated Statements of Operations		8
	Unaudited Consolidated Statements of Comprehensive (Loss) Income		9
	Unaudited Consolidated Statements of Cash Flows		10
	Unaudited Consolidated Statement of Member’s Equity		11
	Notes to Unaudited Consolidated Financial Statements		12
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		27
Item 3.	Quantitative and Qualitative Disclosures about Market Risk		52
Item 4.	Controls and Procedures		55

PART II - OTHER INFORMATION

Item 1.	Legal Proceedings		56
Item 1A.	Risk Factors		56
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		56
Item 3.	Defaults Upon Senior Securities		56
Item 4.	Mine Safety Disclosures		56
Item 5.	Other Information		56
Item 6.	Exhibits		57
Signatures			58

PART I - FINANCIAL INFORMATION

Item 1.

Financial Statements

Sprague Resources LP

Balance Sheets


	September 30, 2013			December 31, 2012
	(Unaudited)
Assets
Current assets:
Cash	$	800		$	800

Total assets	$	800		$	800


Liabilities and partners’ equity
Total liabilities	$	—		$	—


Partners’ equity:
Organizational limited partner		990			990
General partner		10			10
Accumulated deficit		(200	)		(200	)

Total partners’ equity		800			800

Total liabilities and partners’ equity	$	800		$	800

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

Sprague Resources LP

Notes to Unaudited Financial Statements

1.	Nature of Operations

Sprague Resources LP (the “Partnership”) is a Delaware limited partnership formed on June 23, 2011 to engage in any lawful activity 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 sale of energy products, as well as materials handling operations.

In connection with the completion on October 30, 2013 of the initial public offering (the “IPO”) of limited partner interests of the Partnership, Axel Johnson Inc. (the “Parent”) contributed to Sprague Resources Holdings LLC (“Sprague Holdings”) all of the ownership interests in the Predecessor. The Predecessor distributed to a wholly owned subsidiary of Sprague Holdings certain assets and liabilities, including among others, 100% of the equity investment in 9047-1137 Quebec Inc. (“Kildair”) and accounts receivable and cash in an aggregate amount equal to the net proceeds of the IPO. Sprague Holdings then contributed all of the ownership interests in the Predecessor to the Partnership. All of the assets and liabilities of the Predecessor contributed to the Partnership by Sprague Holdings were recorded at the Parent’s historical cost as the foregoing transactions are among entities under common control.

2.	Basis of Presentation

The 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 financial position at September 30, 2013 and December 31, 2012.

The 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, therefore, should be read in conjunction with the consolidated financial statements and related notes of the Partnership included in the prospectus of Sprague Resources dated October 24, 2013, as filed with the SEC on October 28, 2013 (the “Prospectus”).

3.	Subsequent Events

On October 30, 2013, in connection with the closing of the IPO, 8,500,000 of the Partnership’s common units, representing a 42.2% limited partner interest in the Partnership, were sold at an initial public offering price of $18.00 per unit. Total proceeds of the sale of the common units were $153.0 million, before underwriting discounts and commissions, the structuring fee and estimated offering expenses. After the IPO, the Parent owns 1,571,970 common units and 10,071,970 subordinated units, representing an aggregate 57.8% limited partner interest in the Partnership.

Contribution, Conveyance and Assumption Agreement

On October 30, 2013, in connection with the closing of IPO, the Parent, Sprague Holdings, the Partnership, Sprague Resources GP LLC, a Delaware limited liability company and the general partner of the Partnership (the “General Partner”), Sprague Massachusetts Properties LLC, a Delaware limited liability company and a wholly owned subsidiary of Sprague Holdings (“Sprague Massachusetts”), Sprague International Properties LLC, a Delaware limited liability company and a wholly owned subsidiary of Sprague Holdings (“Sprague International”), Sprague Canadian Properties LLC, a Delaware limited liability company and a wholly owned subsidiary of Sprague Holdings (“Sprague Canadian”) and the OLLC entered into a contribution, conveyance and assumption agreement (the “Contribution Agreement”). Pursuant to the Contribution Agreement, among other things, Sprague Holdings conveyed all of the ownership interests in the Predecessor to the Partnership (through the OLLC), in exchange for (a) 1,571,970 common units, representing a 7.8% limited partner interest in the Partnership, (b) 10,071,970 subordinated units, representing a 50% limited partner interest in the Partnership, (c) all of the equity interests in the Partnership classified as incentive distribution rights under the amended and restated agreement of limited partnership of the Partnership and (d) the right to receive the deferred issuance and distribution (as defined in the Contribution Agreement).

Sprague Resources LP

Notes to Unaudited Financial Statements

Omnibus Agreement

On October 30, 2013, in connection with the closing of the IPO, the Partnership, the Parent, Sprague Holdings and the General Partner, entered into an omnibus agreement (the “Omnibus Agreement”). The Omnibus Agreement addresses the agreement of the Parent to offer to the Partnership and to cause the Parent’s controlled affiliates to offer to the Partnership opportunities to acquire certain businesses and assets and the obligation of Sprague Holdings to indemnify the Partnership for certain liabilities. Pursuant to the Omnibus Agreement, the Parent agreed to continue to provide credit support to the Partnership, consistent with past practice, through December 31, 2016, if and to the extent such services are necessary and reasonable, and the Partnership agreed to use its commercially reasonable efforts to reduce, and eventually eliminate, the need for trade credit support from the Parent. The Omnibus Agreement may be terminated (other than with respect to the indemnification provisions) by any party to the Omnibus Agreement in the event that the Parent, directly or indirectly, owns less than 50% of the voting equity power of the General Partner.

Services Agreement

On October 30, 2013, in connection with the closing of the IPO, the Partnership, the General Partner, Sprague Holdings and Sprague Energy Solutions, Inc., a Delaware corporation and a wholly owned subsidiary of the Predecessor (“Sprague Solutions”), entered into an operational services agreement (the “Services Agreement”). Pursuant to the Services Agreement, the General Partner will provide certain general and administrative and operational services to the Partnership and Sprague Holdings, and the Partnership and Sprague Holdings will reimburse the General Partner for all costs and expenses incurred in connection with providing such services to the Partnership and Sprague Holdings. The Services Agreement does not limit the amount that may be reimbursed or paid by the Partnership to the General Partner. The initial term of the Services Agreement will expire on October 30, 2018. The Services Agreement will automatically renew at the end of the initial term for successive one-year terms until terminated in accordance with the terms thereof. The Services Agreement does not limit the ability of the officers and employees of the General Partner to provide services to other affiliates of Sprague Holdings or unaffiliated third parties.

Terminal Operating Agreement

On October 30, 2013, in connection with the closing of the IPO, Sprague Massachusetts and the OLLC entered into an exclusive terminal operating agreement (the “Terminal Operating Agreement”) with respect to the terminal in New Bedford, Massachusetts owned by Sprague Massachusetts. Pursuant to the Terminal Operating Agreement, the OLLC has the exclusive use and operation of, and retains title to all of the refined products stored at, the New Bedford terminal owned by Sprague Massachusetts in exchange for a monthly fee to Sprague Massachusetts. The initial term of the Terminal Operating Agreement will expire on October 30, 2018. The Terminal Operating Agreement will terminate upon 60 days’ written notice from Sprague Holdings or Sprague Massachusetts in the event that Sprague Holdings or Sprague Massachusetts determines that termination is necessary to facilitate the sale or development of the New Bedford terminal. The New Bedford terminal is subject to a purchase and sale agreement pursuant to which a third party may acquire the terminal from Sprague Massachusetts. Subject to certain conditions, such acquisition may be consummated on or before January 5, 2016. If such acquisition is consummated, the Terminal Operating Agreement will automatically terminate.

Long-Term Incentive Plan

The General Partner adopted the Sprague Resources LP 2013 Long-Term Incentive Plan (the “LTIP”) effective immediately prior to the effective date of the IPO, for the benefit of employees, consultants and directors of the General Partner and its affiliates, who provide services to the General Partner or an affiliate. The LTIP provides the Partnership with the flexibility to grant unit options, restricted units, phantom units, unit appreciation rights, cash awards, distribution equivalent rights, substitute awards, and other unit-based awards, or any combination of the foregoing.

The LTIP will initially limit the number of common units that may be delivered pursuant to vested awards to 800,000 common units. On January 1 of each calendar year occurring after the second anniversary of the effective date and prior to the expiration of the LTIP, the total number of common units reserved and available for issuance under the LTIP will increase by 200,000 common units.

Sprague Resources LP

Notes to Unaudited Financial Statements

The LTIP will expire upon the earlier of (i) its termination by the board of directors of the General Partner, (ii) the date common units are no longer available under the LTIP for grants or (iii) the tenth anniversary of the date the LTIP was approved by the General Partner.

Underwriting Agreement

On October 24, 2013, the Partnership, the General Partner, the OLLC and Sprague Holdings (the “Partnership Parties”) entered into an underwriting agreement (the “Underwriting Agreement”) with the underwriters named therein (the “Underwriters”), providing for the offer and sale by the Partnership, and the purchase by the Underwriters, of 8,500,000 common units at a price to the public of $18.00 per common unit ($16.965 per common unit, net of underwriting discounts and before payment of a structuring fee).

The Underwriting Agreement contains customary representations, warranties and agreements of the parties, and customary conditions to closing, obligations to the parties and termination provisions. The Partnership Parties have agreed to indemnify the Underwriters against certain liabilities, including liabilities under the Securities Act of 1933, as amended, and to contribute to payments the Underwriters may be required to make because of any of those liabilities.

Sprague Operating Resources LLC (Predecessor)

Consolidated Balance Sheets


	September 30, 2013			December 31, 2012
	(Unaudited)
	(in thousands)
Assets
Current assets:
Cash and cash equivalents	$	3,313		$	3,691
Accounts receivable, net		191,223			251,246
Inventories		325,085			472,596
Fair value of derivative assets		40,308			30,852
Deferred income taxes		17,508			14,258
Other current assets		31,193			32,858

Total current assets		608,630			805,501

Property, plant and equipment, net		201,234			177,080
Intangibles and other assets, net		18,308			20,772
Goodwill		50,424			50,894

Total assets	$	878,596		$	1,054,247

Liabilities and member’s equity
Current liabilities:
Accounts payable	$	137,892		$	196,776
Accrued liabilities		36,994			48,949
Fair value of derivative liabilities		50,786			49,953
Current portion of long-term debt		463,747			317,186
Current portion of capital leases		709			709

Total current liabilities		690,128			613,573

Commitments and contingencies (Note 9)		—			—
Long-term debt		572			232,007
Long-term capital leases		5,091			5,717
Other liabilities		18,586			19,208
Deferred income taxes		42,201			42,536

Total liabilities		756,578			913,041

Member’s equity:
Member’s equity		129,809			146,779
Accumulated other comprehensive loss, net of tax		(7,791	)		(5,573	)

Total member’s equity		122,018			141,206

Total liabilities and member’s equity	$	878,596		$	1,054,247

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

Sprague Operating Resources LLC (Predecessor)

Unaudited Consolidated Statements of Operations


	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
	(in thousands)						(in thousands)

Net sales	$	940,275		$	703,693		$	3,407,048		$	2,741,299
Cost of products sold		914,574			690,489			3,282,438			2,658,266

Gross margin		25,701			13,204			124,610			83,033
Operating costs and expenses:
Operating expenses		12,844			10,287			40,444			32,393
Selling, general and administrative		12,633			9,870			39,689			32,370
Depreciation and amortization		4,034			2,493			12,471			7,458

Total operating costs and expenses		29,511			22,650			92,604			72,221


Operating (loss) income		(3,810	)		(9,446	)		32,006			10,812
Loss on impairment of fixed assets		—			—			—			(529	)
Other (expense) income		(215	)		(134	)		601			(134	)
Interest income		261			130			521			438
Interest expense		(7,207	)		(4,855	)		(21,846	)		(16,273	)


(Loss) income before income taxes and equity in net income of foreign affiliate		(10,971	)		(14,305	)		11,282			(5,686	)
Income tax benefit (provision)		4,560			6,908			(6,078	)		3,203


(Loss) income before equity in net loss of foreign affiliate		(6,411	)		(7,397	)		5,204			(2,483	)
Equity in net loss of foreign affiliate		—			(3,361	)		—			(1,009	)

Net (loss) income	$	(6,411	)	$	(10,758	)	$	5,204		$	(3,492	)

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

Sprague Operating Resources LLC (Predecessor)

Unaudited Consolidated Statements of Comprehensive (Loss) Income


	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
	(in thousands)						(in thousands)

Net (loss) income	$	(6,411	)	$	(10,758	)	$	5,204		$	(3,492	)
Other comprehensive income (loss), net of tax:
Unrealized (loss) on interest rate swaps
Net loss arising in the period		(165	)		(625	)		(303	)		(1,716	)
Reclassification adjustment for losses realized in income as interest expense		1,292			1,010			3,806			3,099

Net change in unrealized loss on interest rate swaps		1,127			385			3,503			1,383
Tax effect		(452	)		(155	)		(1,408	)		(556	)

		675			230			2,095			827
Foreign currency translation adjustment		853			1,795			(1,812	)		2,052
Unrealized gain (loss) on inter-entity long-term foreign currency transactions		1,313			—			(2,501	)		—

Other comprehensive income (loss)		2,841			2,025			(2,218	)		2,879

Comprehensive (loss) income	$	(3,570	)	$	(8,733	)	$	2,986		$	(613	)

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

Sprague Operating Resources LLC (Predecessor)

Unaudited Consolidated Statements of Cash Flows


	Nine Months Ended September 30,
	2013			2012
	(in thousands)

Cash flows from operating activities
Net income (loss)	$	5,204		$	(3,492	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization		15,056			9,779
Gain on sale of assets		(10	)		(25	)
Gain on insurance recovery		(777	)		—
Impairment of terminal asset		—			529
Provision for doubtful accounts		627			892
Undistributed loss on investment of foreign affiliate		—			1,009
Deferred income taxes		(4,341	)		5,675
Changes in assets and liabilities:
Accounts receivable		56,818			94,819
Inventories		144,242			131,173
Prepaid expenses and other current assets		(80	)		30
Fair value of commodity derivative instruments		(5,142	)		39,471
Accounts payable, accrued liabilities and other		(61,669	)		(56,568	)

Net cash provided by operating activities		149,928			223,292

Cash flows from investing activities
Purchases of property, plant and equipment		(17,074	)		(4,966	)
Proceeds from property insurance settlement		1,867			—
Business acquisition		(20,700	)		—
Proceeds from sale of assets		168			25

Net cash used in investing activities		(35,739	)		(4,941	)

Cash flows from financing activities
Net payments under credit agreements		(82,622	)		(221,000	)
Payments on capital lease liabilities and term debt		(507	)		(188	)
Payments on long-term terminal obligations		(288	)		(477	)
Debt issue costs		(495	)		(293	)
Capital contribution from Parent		10,000			—
Dividend paid to Parent		(40,000	)		(26,900	)
Net (decrease) increase in payable to Parent		(494	)		104
Borrowings of unsecured debt		—			25,000

Net cash used in financing activities		(114,406	)		(223,754	)

Effect of exchange rate changes on cash balances held in foreign currencies		(161	)		(103	)

Net change in cash and cash equivalents		(378	)		(5,506	)
Cash and cash equivalents, beginning of period		3,691			31,829

Cash and cash equivalents, end of period	$	3,313		$	26,323

Supplemental disclosure of cash flow information
Cash paid:
Interest	$	17,670		$	14,970
Taxes	$	3,206		$	2,280

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

Sprague Operating Resources LLC (Predecessor)

Unaudited Consolidated Statements of Member’s Equity


	Member’s Equity			Accumulated Other Comprehensive Loss			Total Member’s Equity
	(in thousands)

Balance at December 31, 2012	$	146,779		$	(5,573	)	$	141,206
Net income		5,204			—			5,204
Other comprehensive loss		—			(2,218	)		(2,218	)
Dividend		(40,000	)		—			(40,000	)
Capital contributions		17,826			—			17,826

Balance at September 30, 2013	$	129,809		$	(7,791	)	$	122,018

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

Sprague Operating Resources LLC (Predecessor)

Notes to Unaudited Consolidated Financial Statements

(in thousands unless otherwise stated)

1.	Description of Business and Summary of Significant Accounting Policies

Company Businesses

On November 7, 2011, Sprague Energy Corp. was converted into a limited liability company and renamed as Sprague Operating Resources LLC (the “Predecessor”). There was no impact to the organization’s structure or ownership as a result of such conversion. The stockholder’s equity was converted to member’s equity and the Predecessor remained a wholly owned subsidiary of Axel Johnson Inc. (the “Parent”).

The Predecessor is one of the largest independent wholesale distributors of refined products in the Northeast United States based on aggregate terminal capacity. The Predecessor owns and/or operates a network of 16 refined products and materials handling terminals located in the Northeast United States and Eastern Canada. The Predecessor also utilizes third-party terminals in the Northeast through which it sells or distributes refined products pursuant to rack, exchange and throughput agreements. The Predecessor has four business segments: refined products, natural gas, materials handling and other operations. The refined products segment purchases a variety of refined products, such as heating oil, diesel, residual fuel oil, asphalt, kerosene, jet fuel and gasoline (primarily from refining companies, trading organizations and producers), and sells them to wholesale, commercial and industrial customers. The natural gas segment purchases, sells and distributes natural gas to commercial and industrial customers in the Northeast and Mid-Atlantic. The Predecessor purchases the natural gas it sells from natural gas producers and trading companies. The materials handling segment offloads, stores and prepares for delivery a variety of customer-owned products, including asphalt, clay slurry, salt, gypsum, coal, petroleum coke, caustic soda, tallow, pulp and heavy equipment. The Predecessor’s other operations include the purchase and distribution of coal and certain commercial trucking activities.

Since October 2007 and through September 30, 2012, the Predecessor, through its wholly-owned subsidiary, Sprague Energy Canada Ltd., owned a 50% equity investment in 9047-1137 Quebec Inc. (“Kildair”). On October 1, 2012, the Predecessor acquired the remaining 50% equity interest in Kildair. See Note 2 – “Acquisitions”. Kildair’s primary business is the distribution of residual fuel oil and asphalt which are included in the refined products segment and the development of crude oil storage and handling capabilities.

In connection with the completion on October 30, 2013 of the initial public offering (the “IPO”) of limited partner interests of Sprague Resources LP, a Delaware limited partnership (“Sprague Resources” or the “Partnership”), the Parent contributed to Sprague Resources Holdings LLC (“Sprague Holdings”) all of the ownership interests in the Predecessor. The Predecessor distributed to a wholly owned subsidiary of Sprague Holdings certain assets and liabilities, including among others, 100% of the equity investment in Kildair and accounts receivable and cash in an aggregate amount equal to the net proceeds of the IPO. Sprague Holdings then contributed all of the ownership interests in the Predecessor to Sprague Resources. All of the assets and liabilities of the Predecessor contributed to Sprague Resources by Sprague Holdings were recorded at the Parent’s historical cost as the foregoing transactions are among entities under common control. See Note 10 – “Subsequent Events – Initial Public Offering”.

Basis of Presentation

The consolidated financial statements included herein reflect all normal and recurring adjustments which, in the opinion of management, are necessary for a fair presentation of the Predecessor’s consolidated financial position at September 30, 2013 and December 31, 2012, the consolidated results of operations and cash flows for the three and nine months ended September 30, 2013 and 2012, respectively. The unaudited results of operations for the interim periods reported are not necessarily indicative of results to be expected for the full year.

The consolidated financial statements were prepared in accordance with the requirements of the Securities and Exchange Commission (“SEC”) for interim financial information. As permitted under those rules, certain notes or other financial information that are normally required by U.S. generally accepted accounting principles (“GAAP”) to be included in annual financial statements have been condensed or omitted from these interim financial statements. These interim financial statements, therefore, should be read in conjunction with the consolidated financial statements and related notes of the Predecessor included in the prospectus of Sprague Resources dated October 24, 2013, as filed with the SEC on October 28, 2013 (the “Prospectus”).

Demand for some of the Predecessor’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 Predecessor’s quarterly operating results.

Sprague Operating Resources LLC (Predecessor)

Notes to Unaudited Consolidated Financial Statements

(in thousands unless otherwise stated)

The Predecessor’s significant accounting policies are described in Note 1—“Description of Business and Summary of Significant Accounting Policies” contained in the Predecessor’s audited consolidated financial statements included in the Prospectus and are the same as are used in preparing these unaudited consolidated financial statements.

Recent Accounting Pronouncements

In July 2013, the FASB issued ASU 2013-10, “Derivatives and Hedging (Topic 815)—Inclusion of the Fed Funds Effective Swap Rate (or Overnight Index Swap Rate) as a Benchmark Interest Rate for Hedge Accounting Purposes”. This amended guidance permits the Fed Funds Effective Swap Rate to be used as a U.S. benchmark interest rate for hedge accounting purposes. The amendments also remove the restriction on using different benchmark rates for similar hedges. The amendments apply to all entities that elect to apply hedge accounting of the benchmark interest rate. This amendment is effective for qualifying new or redesignated hedge relationships entered into after July 17, 2013. The adoption of this ASU is not expected to have a significant impact on the Predecessor’s consolidated financial statements.

In February 2013, the FASB issued ASU No. 2013-02, “Reporting Amounts Reclassified Out of Accumulated Other Comprehensive Income,” which amends ASC 220, “Comprehensive Income.” The amended guidance requires entities to provide information about the amounts reclassified out of accumulated other comprehensive income by component. Additionally, entities are required to present, either on the face of the financial statements or in the notes, significant amounts reclassified out of accumulated other comprehensive income by the respective line items of net income. The amended guidance does not change the current requirements for reporting net income or other comprehensive income. The Predecessor’s adoption of this ASU as of January 1, 2013 did not have a material impact on the consolidated financial statements.

In December 2011, the FASB issued ASU 2011-11, “Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities.” ASU 2011-11 requires an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. Entities are required to disclose both gross and net information about these instruments. ASU 2011-11 is effective for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual periods. The Predecessor’s adoption of ASU 2011-11 as of January 1, 2013 did not have a material impact on the consolidated financial statements, but resulted in additional disclosure regarding fair value measurement.

2.	Acquisitions

Bridgeport Terminal

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

The acquisition was accounted for as a business combination and was financed with a capital contribution of $10.0 million from the Parent (see Note 6—“Related Party Transactions”) and $10.7 million of borrowings under the acquisition line of the Predecessor’s credit facility.

The allocation of the purchase price will be finalized as the Predecessor receives additional information regarding the acquisition, including a final valuation of the assets purchased. The final allocation of this acquisition may be different from the preliminary estimates presented below.

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


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

Net assets acquired	$	20,700

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

Sprague Operating Resources LLC (Predecessor)

Notes to Unaudited Consolidated Financial Statements

(in thousands unless otherwise stated)

Kildair

Prior to October 1, 2012

In October 2007, the Predecessor purchased a 50% equity interest in Kildair for $38.7 million. The share purchase agreement provided for the Predecessor to acquire the remaining 50% of Kildair in 2012, subject to terms and conditions within the discretion of the Predecessor, for an additional $27.5 million Canadian, plus a potential earn-out payment if EBITDA over the five year period exceeded $55.0 million Canadian. The difference between the acquisition cost and the fair value of net assets acquired in October 2007 of $13.2 million was allocated to various assets and liabilities based on their respective fair values with amortization recorded over the useful lives of the assets or liabilities that gave rise to the difference. From October 2007 through September 30, 2012, the investment in Kildair was accounted for using the equity method of accounting and the Predecessor’s share of its results were recorded as equity in net loss of foreign affiliate in the Consolidated Statements of Operations.

Summary financial information for Kildair, not adjusted for the percentage of ownership held by the Predecessor, follows:


	Three Months Ended September 30, 2012			Nine Months Ended September 30, 2012
Net sales	$	207,368		$	422,097
Gross margin		(2,624	)		15,814
(Loss) income from operations		(7,540	)		1,596
Net loss		(6,653	)		(1,667	)

The Predecessor’s equity share of loss from its investment in Kildair, which includes amortization of the excess of the fair value over the cost of the assets acquired, was $(3.4) million, net of tax, and $(1.0) million, net of tax, for the three and nine months ended September 30, 2012, respectively.

On or after October 1, 2012

On October 1, 2012 (the “acquisition date”), the Predecessor acquired control of Kildair by purchasing the remaining 50% equity interest. Since the acquisition date, the assets, liabilities and results of operations of Kildair have been consolidated into the Predecessor’s consolidated financial statements.

Kildair has 3.2 million barrels of storage capacity and an infrastructure that includes an asphalt plant, loading racks, testing laboratory and a marine dock on the St. Lawrence River. The purchase of this facility augments the Predecessor’s supply, storage and marketing opportunities and provides new opportunities in asphalt marketing and expanded materials handling capabilities. The acquisition-date fair value of the consideration consisted of cash of $73.0 million (including an $8.7 million redemption of preferred shares) and the Predecessor’s previous 50% equity interest. The Predecessor recognized a gain of $1.5 million as a result of re-measuring to fair value its prior equity interest held before the business combination. The gain is calculated as the difference between the acquisition-date fair value ($57.0 million) and the book value immediately prior to the acquisition date ($55.5 million). The book value of the equity interest included currency translation adjustment balances in accumulated other comprehensive loss. The fair value was determined using valuation techniques including the discounted cash flow approach and the market multiple approach (enterprise value of earnings before interest, taxes, depreciation and amortization). The discounted cash flow approach incorporates assumptions including estimated future cash flows and a discount rate that reflects consideration of risk free rates as well as market risk.

The market multiple approach incorporates market information from comparable companies. The gain, which resulted in no income tax expense, was recorded in 2012 as gain on acquisition of a business in the Consolidated Statements of Operations.

Sprague Operating Resources LLC (Predecessor)

Notes to Unaudited Consolidated Financial Statements

(in thousands unless otherwise stated)

The amount of net sales and net income (loss) of Kildair included in the Predecessor’s unaudited consolidated results for the three and nine months ended September 30, 2013 are as follows:


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

The following represents the pro forma consolidated net sales and net loss as if Kildair had been included in the unaudited consolidated results of the Predecessor for the three and nine months ended September 30, 2012:


	Three Months Ended September 30, 2012			Nine Months Ended September 30, 2012
Net sales	$	911,061		$	3,163,396
Net loss		(14,837	)		(7,071	)

These amounts have been calculated after applying the Predecessor’s accounting policies and adjusting the results of Kildair to reflect the additional cost of products sold and depreciation and amortization that would have been charged assuming the fair value adjustments to inventory, property, plant and equipment and intangible assets had been applied on January 1, 2012, together with the consequential tax effects.

Kildair is not part of Sprague Resources’ assets or operations following the completion of the IPO on October 30, 2013. See Note 10 – “Subsequent Events – Initial Public Offering”.

3.	Accumulated Other Comprehensive Loss, Net of Tax

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


	September 30, 2013			December 31, 2012
Change in fair value of interest rate swaps, net of tax	$	(2,170	)	$	(4,265	)
Cumulative foreign currency translation loss adjustment, net of tax		(5,621	)		(1,308	)

Accumulated other comprehensive loss, net of tax	$	(7,791	)	$	(5,573	)

The cumulative foreign currency translation loss adjustment as of September 30, 2013 and December 31, 2012, includes a cumulative loss of $3.3 million and $0.8 million, respectively, related to the conversion of intercompany advances not anticipated to be settled in the foreseeable future.

4.	Inventories


	September 30, 2013		December 31, 2012
Petroleum and related products	$	301,428	$	440,362
Asphalt		18,211		25,867
Coal		3,639		4,355
Natural gas		1,807		2,012

Inventories	$	325,085	$	472,596

Due to changing market conditions, the Predecessor recorded a provision of $6.2 million as of September 30, 2013 and $6.3 million as of December 31, 2012, respectively, to write-down petroleum and natural gas inventory to net realizable value. These charges are included in cost of products sold in the Unaudited Consolidated Statements of Operations.

Sprague Operating Resources LLC (Predecessor)

Notes to Unaudited Consolidated Financial Statements

(in thousands unless otherwise stated)

Debt


	September 30, 2013		December 31, 2012
Current debt
Credit agreement	$	379,200	$	254,060
Credit agreement – Canadian subsidiary		38,181		35,183
Unsecured debt		25,000		25,000
Term debt – Canadian subsidiary		21,127		2,833
Other		239		110

Current debt		463,747		317,186

Long-term debt
Credit agreement		—		210,640
Term debt – Canadian subsidiary		—		21,245
Other		572		122

Long-term debt		572		232,007

Total debt	$	464,319	$	549,193

The following table summarizes the future annual principal payments for debt obligations as of September 30, 2013:


	Credit Agreements		Unsecured Debt		Term Debt and Other		Total
Twelve months ending September 30, 2014	$	417,381	$	25,000	$	21,366	$	463,747
Twelve months ending September 30, 2015		—		—		183		183
Twelve months ending September 30, 2016 and thereafter		—		—		389		389

	$	417,381	$	25,000	$	21,938	$	464,319

Credit Agreement

The Predecessor’s revolving credit agreement (the “Credit Agreement”) was refinanced in May 2010 and has a maturity date of May 28, 2014. The Credit Agreement is secured by substantially all of the Predecessor’s assets and includes a $625.0 million working capital facility used to fund working capital and letters of credit as well as a $175.0 million acquisition facility. Borrowings under the Credit Agreement bear interest based on LIBOR, plus a specified margin, which is a function of the utilization of the Credit Agreement. The weighted average interest rate at September 30, 2013 and December 31, 2012, was 3.1% and 3.4%, respectively. The current portion of the Credit Agreement at September 30, 2013 consists of all outstanding borrowings, as the agreement is scheduled to mature on May 28, 2014. The current portion of the Credit Agreement at December 31, 2012 represents the amount the Predecessor intends to repay during the following twelve-month period.

As of September 30, 2013 and December 31, 2012, working capital facility borrowings were $246.5 million and $347.3 million, respectively, and outstanding letters of credit were $40.7 million and $92.0 million, respectively. The working capital facility is subject to borrowing base reporting and as of September 30, 2013 and December 31, 2012, had a borrowing base of $379.9 million and $529.3 million, respectively. As of September 30, 2013, excess availability under the working capital facility was $92.7 million.

As of September 30, 2013 and December 31, 2012, acquisition line borrowings were $132.7 million and $117.4 million, respectively. As of September 30, 2013, excess availability under the acquisition facility was $42.3 million.

The Credit Agreement contains certain restrictions and covenants among which are a minimum level of net working capital and tangible net worth, limitation on the incurrence of indebtedness and fixed charge coverage and funded debt leverage ratios. The Credit Agreement limits the Predecessor’s ability to make distributions in the event of defaults as defined in the Credit Agreement. As of September 30, 2013, the Predecessor was in compliance with these financial covenants.

Sprague Operating Resources LLC (Predecessor)

Notes to Unaudited Consolidated Financial Statements

(in thousands unless otherwise stated)

Credit Agreement—Canadian Subsidiary

The Predecessor’s Canadian subsidiary utilizes a revolving credit agreement (the “Canadian Credit Agreement”) that has a maturity date of April 30, 2014, and is secured by substantially all of the Canadian subsidiary’s assets. The Canadian Credit Agreement is used to fund working capital, letters of credit and letters of guarantee for an amount up to $107.0 million. Amounts can be borrowed in either U.S. or Canadian dollars. The loan bears interest at the prime rate plus 1.5% or the bank’s cost of funds plus 3.0% and is renewable annually. The weighted average interest rate at September 30, 2013 and December 31, 2012 was 4.9% and 4.5%, respectively.

As of September 30, 2013 and December 31, 2012, borrowings under the Canadian Credit Agreement were $38.2 million and $35.2 million, respectively. As of September 30, 2013, there were no outstanding letters of credit. The Canadian Credit Agreement is subject to borrowing base reporting and as of September 30, 2013 and December 31, 2012, had a borrowing base of $84.0 million and $89.1 million, respectively. As of September 30, 2013, excess availability under the Canadian Credit Agreement was $45.8 million.

The terms of the Canadian Credit Agreement require the Canadian subsidiary to maintain specific levels of working capital, total liabilities to equity ratio, maintenance of a fixed charge coverage ratio, a limit on capital expenditures and a maximum net position for products consisting of heavy fuel oil and asphalt. Furthermore, the Canadian subsidiary is restricted in its ability to pay a dividend if such dividend would place them in default on any of the aforementioned covenants. The Predecessor has entered into an “undertaking” with the Canadian Credit Agreement lenders whereby in the event of noncompliance with certain of these covenants the Predecessor will advance to the Canadian subsidiary up to $20.0 million in the form of subordinated notes to satisfy any such deficiency. As of September 30, 2013, the Predecessor had advanced $10.4 million under this “undertaking” and as a result the Canadian subsidiary was in compliance with these financial covenants.

Unsecured Debt

During September 2012, the Predecessor borrowed $25.0 million of unsecured debt bearing interest at LIBOR (0.2% at September 30, 2013 and December 31, 2012) plus 4.0%. The unsecured debt is owed to a third-party financial institution and was originally scheduled to mature on September 24, 2013. On September 5, 2013, this note was extended to February 28, 2014.

Term Debt—Canadian Subsidiary

The Predecessor’s Canadian subsidiary has a term loan outstanding that is payable in monthly installments of approximately $0.2 million, with a final maturity of $19.3 million due in June 2014. Interest is payable at the Canadian prime rate (3.0% at September 30, 2013 and December 31, 2012) plus 2.2%. The term loan is secured by the assets of the Canadian subsidiary.

6.	Related Party Transactions

The Parent charged the Predecessor $0.3 million and $1.0 million for each of the three and nine month periods ended September 30, 2013 and 2012, respectively, for oversight and monitoring of the Predecessor. Such amounts are included in selling, general and administrative expenses in the Unaudited Consolidated Statements of Operations. Intercompany activities are settled monthly and do not bear interest. There were no material intercompany accounts receivable or intercompany accounts payable balances outstanding with the Parent as of September 30, 2013 and December 31, 2012.

In February 2013 and September 2013, the Predecessor paid a dividend to the Parent of $22.5 million and $17.5 million, respectively, as permitted by the Credit Agreement.

During July 2013 the Predecessor received a capital contribution of $10.0 million from the Parent in connection with a business acquisition. (see Note 2 – “Acquisitions”).

Sprague Operating Resources LLC (Predecessor)

Notes to Unaudited Consolidated Financial Statements

(in thousands unless otherwise stated)

7.	Segment Reporting

The Predecessor 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 Predecessor has four reporting operating segments that comprise the structure used by the chief operating decision makers (CEO and CFO) to make key operating decisions and assess performance. These segments are refined products, natural gas, materials handling and other activities. Segment information of Kildair has been included since the Kildair acquisition date of October 1, 2012.

The Predecessor’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 Predecessor has wholesale customers who resell the refined products they purchase from the Predecessor and commercial customers who consume the refined products they purchase from the Predecessor. The Predecessor’s wholesale customers consist of home heating oil retailers and diesel fuel and gasoline resellers. The Predecessor’s commercial customers include federal and state agencies, municipalities, regional transit authorities, large industrial companies, hospitals and educational institutions.

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

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

The Predecessor’s other activities include the purchase, sale and distribution of coal and commercial trucking activities unrelated to its refined products segment. Other activities are not reported separately as they represent less than 10% of consolidated net sales and adjusted gross margin.

The Predecessor evaluates segment performance based on adjusted gross margin, which is gross margin decreased by total commodity derivative gains and losses included in net income (loss) and increased by realized commodity derivative gains and losses included in net income (loss), before allocations of corporate, terminal and trucking operating costs, depreciation, amortization and interest. Based on the way the business is managed, it is not reasonably possible for the Predecessor to allocate the components of operating costs and expenses among the operating segments. There were no significant intersegment sales for any of the periods presented below.

Sprague Operating Resources LLC (Predecessor)

Notes to Unaudited Consolidated Financial Statements

(in thousands unless otherwise stated)

Summarized financial information for the Predecessor’s reportable segments for the three and nine months ended September 30, 2013 and 2012 is presented in the table below:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
Net sales:
Refined products	$	879,691		$	651,030		$	3,148,743		$	2,543,622
Natural gas		49,623			43,105			222,704			167,815
Materials handling		7,185			7,713			21,713			23,673
Other		3,776			1,845			13,888			6,189


Net sales	$	940,275		$	703,693		$	3,407,048		$	2,741,299


Adjusted gross margin(1):
Refined products	$	25,447		$	19,692		$	78,593		$	55,691
Natural gas		4,415			2,773			28,401			18,356
Materials handling		7,181			7,660			21,700			23,464
Other		1,000			369			3,369			1,237


Adjusted gross margin		38,043			30,494			132,063			98,748
Reconciliation to gross margin(2):
Deduct: total commodity derivative losses included in net (loss) income(3)		(23,051	)		(31,086	)		(21,200	)		(26,759	)
Add: realized commodity derivative losses included in net (loss) income(3)		10,709			13,796			13,747			11,044


Gross margin		25,701			13,204			124,610			83,033


Operating costs and expenses not allocated to operating segments:
Operating expenses		12,844			10,287			40,444			32,393
Selling, general and administrative		12,633			9,870			39,689			32,370
Depreciation and amortization		4,034			2,493			12,471			7,458


Total operating costs and expenses		29,511			22,650			92,604			72,221


Operating (loss) income		(3,810	)		(9,446	)		32,006			10,812
Loss on impairment of assets		—			—			—			(529	)
Other (expense) income		(215	)		(134	)		601			(134	)
Interest income		261			130			521			438
Interest expense		(7,207	)		(4,855	)		(21,846	)		(16,273	)
Income tax benefit (provision)		4,560			6,908			(6,078	)		3,203
Equity in net loss of foreign affiliate		—			(3,361	)		—			(1,009	)


Net (loss) income	$	(6,411	)	$	(10,758	)	$	5,204		$	(3,492	)

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

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

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

The Predecessor had no single customer whose revenue was greater than 10% of total net sales for either the three or nine months ended September 30, 2013 and 2012. The Predecessor’s foreign sales, primarily sales of refined products, asphalt and natural gas to its customers in Canada, were $70.5 million and $198.0 million for the three and nine months ended September 30, 2013, respectively. The Predecessor’s foreign sales were not significant for either the three or nine months ended September 30, 2012.

Segment Assets

Due to the comingled nature and uses of the Predecessor’s fixed assets, the Predecessor 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 September 30, 2013, goodwill for the refined products, natural gas, materials handling and other operating segments amounted to $37.8 million, $4.4 million, $7.0 million and $1.2 million, respectively.

Sprague Operating Resources LLC (Predecessor)

Notes to Unaudited Consolidated Financial Statements

(in thousands unless otherwise stated)

8.	Financial Instruments and Off-Balance Sheet Risk

Cash, Cash Equivalents and Accounts Receivable

As of September 30, 2013 and December 31, 2012, the carrying amounts of cash, cash equivalents and accounts receivable approximated fair value because of the short maturity of these instruments. As of September 30, 2013 and December 31, 2012, the carrying value of the Predecessor’s debt approximated fair value due to the short-term maturity and variable interest nature of these instruments.

Derivative Instruments

The following tables present all financial assets and financial liabilities of the Predecessor measured at fair value on a recurring basis as of September 30, 2013 and December 31, 2012:


	As of September 30, 2013
	Fair Value Measurement		Quoted Prices in Active Markets Level 1		Significant Other Observable Inputs Level 2		Significant Unobservable Inputs Level 3
Financial assets:
Commodity exchange contracts	$	172	$	172	$	—	$	—
Commodity fixed forwards		39,317		—		39,317		—
Commodity swaps and options		579		—		579		—

Commodity derivatives		40,068		172		39,896		—
Currency swaps		240		—		240		—

Total	$	40,308	$	172	$	40,136	$	—

Financial liabilities:
Commodity fixed forwards	$	45,928	$	—	$	45,928	$	—
Commodity swaps and options		1,228		—		1,228		—

Commodity derivatives		47,156		—		47,156		—
Interest rate swaps		3,630		—		3,630		—

Total	$	50,786	$	—	$	50,786	$	—


	As of December 31, 2012
	Fair Value Measurement		Quoted Prices in Active Markets Level 1		Significant Other Observable Inputs Level 2		Significant Unobservable Inputs Level 3
Financial assets:
Commodity fixed forwards	$	30,235	$	—	$	30,235	$	—
Commodity swaps and options		597		—		597		—

Commodity derivatives		30,832		—		30,832		—
Currency swaps		20		—		20		—

Total	$	30,852	$	—	$	30,852	$	—

Financial liabilities:
Commodity exchange contracts	$	9	$	9	$	—	$	—
Commodity fixed forwards		42,247		—		42,247		—
Commodity swaps and options		319		—		319		—

Commodity derivatives		42,575		9		42,566		—
Interest rate swaps		7,133		—		7,133		—
Currency swaps		245		—		245		—

Total	$	49,953	$	9	$	49,944	$	—

Sprague Operating Resources LLC (Predecessor)

Notes to Unaudited Consolidated Financial Statements

(in thousands unless otherwise stated)

The Predecessor enters into derivative contracts with counterparties, some of which are subject to master netting arrangements, which allow net settlements under certain conditions. The Predecessor presents derivatives at gross fair values in the Consolidated Balance Sheets. Information related to these offsetting arrangements as of September 30, 2013 and December 31, 2012 follows:


	As of September 30, 2013
									Gross Amount Not Offset in the Balance Sheet
	Gross Amounts of Recognized Assets/Liabilities			Gross Amount Offset in the Balance Sheet		Amounts of Asset/Liabilities in Balance Sheet			Financial Instruments			Cash Collateral Posted			Net Amount
Commodity derivative assets	$	40,068		$	—	$	40,068		$	(6,561	)	$	(100	)	$	33,407
Currency swap derivative assets		240			—		240			—			—			240
Commodity derivative liabilities		(47,156	)		—		(47,156	)		6,561			—			(40,595	)
Interest rate swap derivative liabilities		(3,630	)		—		(3,630	)		—			—			(3,630	)
Currency swap derivative liabilities		—			—		—			—			—			—

	As of December 31, 2012
									Gross Amount Not Offset in the Balance Sheet
	Gross Amounts of Recognized Assets/Liabilities			Gross Amount Offset in the Balance Sheet		Amounts of Asset/Liabilities in Balance Sheet			Financial Instruments			Cash Collateral Posted			Net Amount
Commodity derivative assets	$	30,832		$	—	$	30,832		$	(3,163	)	$	(94	)	$	27,575
Currency swap derivative assets		20			—		20			—			—			20
Commodity derivative liabilities		(42,575	)		—		(42,575	)		3,163			—			(39,412	)
Interest rate swap derivative liabilities		(7,133	)		—		(7,133	)		—			—			(7,133	)
Currency swap derivative liabilities		(245	)		—		(245	)		—			—			(245	)

Commodity Derivatives

The Predecessor 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 Predecessor’s risk management guidelines, the Predecessor utilizes futures contracts, forward contracts, swaps, options and other derivatives to generate profits from changes in market prices. The Predecessor invests in futures and over-the-counter (“OTC”) transactions either on regulated exchanges or in the OTC market. Futures contracts are exchange-traded contractual commitments to either receive or deliver a standard amount or value of a commodity at a specified future date and price, with some futures contracts based on cash settlement rather than a delivery requirement. Futures exchanges typically require investors to provide margin deposits as security. OTC contracts, which may or may not require margin deposits as security, involve parties that have agreed either to exchange cash payments or deliver or receive the underlying commodity at a specified future date and price. The Predecessor posts initial margin with futures transaction brokers, along with variation margin, which is paid or received on a daily basis, and is included in other current assets in the Consolidated Balance Sheets. In addition, the Predecessor may either pay or receive margin based upon exposure with counterparties. Payments made by the Predecessor are included in other current assets, whereas payments received by the Predecessor are included in accrued liabilities in the Consolidated Balance Sheets. Substantially all of the Predecessor’s commodity derivative contracts outstanding as of September 30, 2013 will settle prior to December 31, 2014.

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

The Predecessor 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.

Sprague Operating Resources LLC (Predecessor)

Notes to Unaudited Consolidated Financial Statements

(in thousands unless otherwise stated)

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 Predecessor utilizes fair value measurements based on Level 2 inputs for its fixed forward contracts, over-the-counter commodity price swaps, interest rate swaps and forward currency contracts.

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

The Predecessor 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 Predecessor had no right to reclaim, or obligation to return, cash collateral as of September 30, 2013 or December 31, 2012.

The following table presents total realized and unrealized (losses) and gains on derivative instruments utilized for commodity risk management purposes for the three and nine months ended September 30, 2013 and 2012. Such amounts are included in cost of products sold in the Unaudited Consolidated Statements of Operations:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012

Refined products contracts	$	(9,142	)	$	(25,679	)	$	2,921		$	(22,117	)
Natural gas contracts		(13,909	)		(5,407	)		(24,121	)		(4,642	)

Total	$	(23,051	)	$	(31,086	)	$	(21,200	)	$	(26,759	)

Included in realized and unrealized (losses) and gains on derivative instruments above are realized and unrealized (losses) and gains on discretionary refined products trading of $(1.8) million during the three months ended September 30, 2012, and $(1.2) million and $(0.5) million during the nine months ended September 30, 2013 and 2012, respectively. There was no significant discretionary refined products trading activity during the three months ended September 30, 2013.

Sprague Operating Resources LLC (Predecessor)

Notes to Unaudited Consolidated Financial Statements

(in thousands unless otherwise stated)

The following table presents the gross volume of commodity derivative instruments outstanding as of September 30, 2013 and December 31, 2012:


	As of September 30, 2013
	Refined Products (Barrels)			Natural Gas (MMBtus)
Long contracts		6,791			88,415
Short contracts		(10,803	)		(68,104	)

	As of December 31, 2012
	Refined Products (Barrels)			Natural Gas (MMBtus)
Long contracts		7,844			94,443
Short contracts		(11,829	)		(70,432	)

Interest Rate Derivatives

The Predecessor has entered into interest rate swaps to manage its exposure to changes in interest rates on its Credit Agreement. The Predecessor swaps the variable LIBOR interest rate payable under the Credit Agreement for fixed LIBOR interest rates. The Predecessor’s interest rates swaps hedge actual and forecasted LIBOR borrowings and have been designated as cash flow hedges. Counterparties to the Predecessor’s interest rate swaps are large multinational banks and the Predecessor does not believe there is a material risk of counterparty non-performance. At September 30, 2013, the Predecessor held six interest rate swap agreements with a notional value of $210.0 million. The cash flow hedges at September 30, 2013 expire at various dates through January 2015.

There was no material ineffectiveness determined for the cash flow hedges for each of the three and nine months ended September 30, 2013 and 2012, respectively. Any ineffectiveness is recorded as interest expense in the Unaudited Consolidated Statements of Income.

The Predecessor 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 September 30, 2013, the amount of unrealized losses, net of tax, expected to be reclassified to earnings during the following twelve-month period was approximately $1.7 million.

The following table presents the location of the losses on derivative contracts designated as cash flow hedging instruments reported in the Unaudited Consolidated Statements of Comprehensive (Loss) Income for the three and nine months ended September 30, 2013 and 2012:


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

	Three Months Ended September 30, 2012				Nine Months Ended September 30, 2012
	Amount of Derivative Loss Recognized in OCL		Amount of Derivative Loss Reclassified From Accumulated OCL Into Income		Amount of Derivative Loss Recognized in OCL		Amount of Derivative Loss Reclassified From Accumulated OCL Into Income
Interest rate swaps	$	625	$	1,010	$	1,716	$	3,099

Sprague Operating Resources LLC (Predecessor)

Notes to Unaudited Consolidated Financial Statements

(in thousands unless otherwise stated)

Currency Derivatives

The Predecessor’s Canadian subsidiary enters into forward currency contracts to manage the risk of currency rate fluctuations between its U.S. dollar denominated activity and the Canadian dollar which is its functional currency. At September 30, 2013, the Predecessor’s Canadian subsidiary has entered into a series of forward currency contracts that mature through October 2013. The contracts obligated the Canadian subsidiary to purchase approximately $43.0 million in U.S. dollars at exchange rates ranging from 1.031 to 1.041. The U.S. to Canadian dollar exchange rate was 1.031 at September 30, 2013.

9.	Commitments and Contingencies

Legal, Environmental and Other Proceedings

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

10.

Subsequent Events - Initial Public Offering

On October 30, 2013, Sprague Resources completed the IPO of 8,500,000 of its common units, representing a 42.2% limited partner interest in Sprague Resources at an initial public offering price of $18.00 per unit. Total proceeds of the sale of the common units were $153.0 million, before underwriting discounts and commissions, the structuring fee and estimated offering expenses. After the IPO, the Parent owns 1,571,970 common units and 10,071,970 subordinated units, representing an aggregate 57.8% limited partner interest in Sprague Resources.

Contribution, Conveyance and Assumption Agreement

On October 30, 2013, in connection with the closing of IPO, the Parent, Sprague Holdings, the Partnership, the General Partner, Sprague Massachusetts, Sprague International, Sprague Canadian and the OLLC, entered into a Contribution Agreement. Pursuant to the Contribution Agreement, the following transactions, among other things, occurred:

•

The Parent contributed all of the membership interests in the OLLC to Holdings;

•

OLLC assigned to the General Partner certain corporate assets;

•

OLLC assigned to Sprague International (i) notes receivable aggregating $79.0 million; (ii) all of the equity interests in Ekotek Inc., a Delaware corporation; (iii) all of the equity interests in Sprague Massachusetts; (iv) all of the equity interests in Sprague New York Properties LLC, a Delaware limited liability company; and (v) all of the assets of the Bucksport, Portsmouth and Oceanside Terminals;

•

OLLC assigned to Sprague Massachusetts certain assets and liabilities associated with the New Bedford terminal;

•

Sprague International assumed approximately $25.0 million of OLLC unsecured debt and approximately $39.5 million of OLLC long-term acquisition debt;

•

OLLC assigned to Sprague Canadian all of the interests in Kildair Service Ltd.;

•

OLLC assigned to Holdings $130.4 million of its accounts receivable and $10.0 million in cash;

•

Holdings conveyed to Sprague Resources all of the membership interests in the OLLC in exchange for (a) 1,571,970 Common Units, representing a 7.8% limited partner interest in the Partnership, (b) 10,071,970 Subordinated Units, representing a 50% limited partner interest in the Partnership, (c) all of the equity interests in the Partnership classified as incentive distribution rights under the Partnership Agreement, and (d) the right to receive the deferred issuance and distribution (as defined in the Contribution Agreement);

Sprague Operating Resources LLC (Predecessor)

Notes to Unaudited Consolidated Financial Statements

(in thousands unless otherwise stated)

•

Sprague Resources redeemed the initial interests of the General Partner and Sprague Holdings and refunded the General Partner’s initial contribution of $10 and Holding’s initial contribution of $990;

•

The General Partner’s 1.0% general partner interest in Sprague Resources was converted to a non-economic general partner interest in Sprague Resources;

•

Sprague Resources, the Parent, Sprague Holdings and the General Partner entered into an Omnibus Agreement;

•

Sprague Resources, the General Partner, Sprague Holdings and Sprague Energy entered into a Services Agreement; and

•

Sprague Massachusetts and the OLLC entered into a Terminal Operating Agreement.

New Credit Agreement

On October 30, 2013, in connection with the closing of the IPO, the OLLC entered into a new revolving credit agreement (the “New Credit Agreement”). The New Credit Agreement will mature on October 30, 2018. There are two revolving credit facilities under the New Credit Agreement:

•

A working capital facility of up to $750.0 million to be used for working capital loans and letters of credit in the principal amount equal to the lesser of the borrowing base and $750.0 million; and

•

An acquisition facility of up to $250.0 million to be used for loans and letters of credit to fund capital expenditures and acquisitions.

Sprague Resources and each of its subsidiaries are guarantors of all obligations under the New Credit Agreement. All obligations under the New Credit Agreement are secured by substantially all of the assets of Sprague Resources and its subsidiaries.

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

The specified margin for the working capital facility under the New Credit Agreement will range from 1.00% to 1.50% for loans bearing interest at the Alternate Base Rate, and from 2.00% to 2.50% for loans bearing interest at the Eurodollar Rate and letters of credit issued under the working capital facility. In addition, Sprague Resources will incur a commitment fee based on the unused portion of the working capital facility at a rate ranging from 0.375% to 0.50% per annum.

The specified margin for the acquisition facility under the New Credit Agreement will range from 2.00% to 2.25% for loans bearing interest at the Alternate Base Rate, and from 3.00% to 3.25% for loans bearing interest at the Eurodollar Rate and letters of credit issued under the acquisition facility. In addition, Sprague Resources will incur a commitment fee on the unused portion of the acquisition facility at a rate ranging from 0.375% to 0.50% per annum.

The New Credit Agreement contains various covenants and restrictive provisions that, among other things, prohibit Sprague Resources from making distributions to unitholders if any event of default occurs or would result from the distribution. In addition, the New Credit Agreement contains various covenants that are usual and customary for a financing of this type, size and purpose, including, among others, financial covenants requiring a minimum EBITDA-to-fixed charge ratio of 1.2:1.0 and a maximum total leverage-to-EBITDA ratio of 4.5:1.0, as well as covenants relating to Sprague Resources’ ability to grant liens, make certain investments or acquisitions, dispose of assets and incur additional indebtedness.

The New 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, material judgments and events constituting a change of control. If an event of default exists under the New Credit Agreement, the lenders will be able to accelerate the maturity of the New Credit Agreement.

Sprague Operating Resources LLC (Predecessor)

Notes to Unaudited Consolidated Financial Statements

(in thousands unless otherwise stated)

Change in Tax Status

Prior to the IPO, the Predecessor prepared its income tax provision as if it operated as a stand-alone taxpayer for all periods presented in accordance with a pre-existing tax sharing agreement between the Predecessor and the Parent. Commencing with the IPO, the Predecessor will be treated as a pass-through entity for federal income tax purposes. As a result, all income, expenses, gains, losses and tax credits generated flow through to its owners and, accordingly, do not result in a provision for federal income taxes and certain state income taxes. Pro forma consolidated net (loss) income for the three months ended September 30, 2013 and 2012, and the nine months ended September 30, 2013 and 2012, calculated as if the Predecessor had been converted to a partnership, resulting in the elimination of U.S. federal income taxes, as well as the reduction on income taxes in certain state jurisdictions, is $(11.8) million, $(17.3) million, $11.9 million and $(6.6) million, respectively.

Item 2.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Cautionary Statements Concerning Forward-Looking Statements

This Quarterly Report contains “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 risk factors included in Part II, Item 1A “Risk Factors” of this Quarterly Report as well as the following risks and uncertainties:

•

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

•

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

•

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

•

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

•

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

•

Our business is seasonal and generally our financial results are lower in the second and third quarters of the calendar year, which may result in our need to borrow money in order to make quarterly distributions to our unitholders during these quarters. Warmer weather conditions could adversely affect our home heating oil 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 affected if we are unable to renegotiate or replace such contracts.

•

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

•

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

•

Any disruptions in our labor force could affect our business.

•

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

•

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

•

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

•

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

•

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

•

The condition of credit markets may adversely affect us.

•

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

•

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

The 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 on Form 10-Q (“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, refer to Sprague Operating Resources LLC, our “Predecessor” for accounting purposes and the successor to Sprague Energy Corp., also referenced as “our Predecessor,” and when used in the present tense or prospectively, refer to Sprague Resources LP and its subsidiaries. Unless the context otherwise requires, references to “Axel Johnson” or the “Parent” refer to Axel Johnson Inc. and its controlled affiliates, collectively, other than Sprague Resources, its subsidiaries and its general partner. References to “Sprague Holdings” refer to Sprague Resources Holdings LLC, a wholly owned subsidiary of Axel Johnson and the owner of our general partner. References to our “general partner” refer to Sprague Resources GP LLC.

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the Predecessor’s unaudited condensed combined financial statements and related notes thereto included elsewhere in this Quarterly Report and the Predecessor’s audited financial statements and notes thereto and management’s discussion and analysis of financial condition and results of operations for the year ended December 31, 2012 included in our final prospectus dated October 24, 2013, as filed with the Securities Exchange Commission (the “SEC”) pursuant to Rule 424 on October 28, 2013 (the “Prospectus”).

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

In connection with the completion of our initial public offering on October 30, 2013 (the “IPO”), Axel Johnson contributed to Sprague Holdings all of the ownership interests in our Predecessor. Sprague Holdings then contributed to us all of the ownership interests in our Predecessor. For a discussion of transactions concurrent with the contribution, see “Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Recent Developments – Initial Public Offering.”

Please read Part I, Item 1. “Cautionary Statement Regarding Forward-Looking Statements” and Part II, Item 1A.“Risk Factors” for information regarding certain risks inherent in our business.

Overview

We are a Delaware limited partnership engaged in the purchase, storage, distribution and sale of refined products and natural gas, and we also 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. Excluding Kildair, we own and/or operate a network of 15 refined products and materials handling terminals strategically located throughout the Northeast that have a combined storage capacity of approximately 9.1 million barrels for refined products and other liquid materials, as well as approximately 1.5 million square feet of materials handling capacity. We also have an aggregate of approximately 1.5 million barrels of additional storage capacity attributable to 43 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 50 third-party terminals in the Northeast through which we sell or distribute refined products pursuant to rack, exchange and throughput agreements.

We operate under four business segments: refined products, natural gas, materials handling and other operations. We evaluate the performance of our segments using adjusted gross margin, which is a non-GAAP financial measure used by management and external users of our consolidated financial statements to assess the economic results of operations. For a description of how we define adjusted gross margin, see “Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations — How Management Evaluates Our Results of Operations.” For a reconciliation of adjusted gross margin to the GAAP measure most directly comparable thereto, see “Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations —Results of Operations.”

On October 1, 2012, our Predecessor acquired control of 9047-1137 Quebec Inc., a Canadian distributor of residual fuel oil and asphalt and a commercial trucking business (“Kildair”), by purchasing the remaining 50% equity interest. Kildair is now a wholly-owned subsidiary of our Predecessor and is not part of our net assets following completion of the IPO. Since October 1, 2012, the assets, liabilities and results of operations of Kildair have been consolidated into our Predecessor’s financial statements, including our adjusted gross margin. We record Kildair’s residual fuel oil and asphalt business in our refined products segment and their commercial trucking business in our other operations segment. Prior to October 1, 2012, the results of operations of Kildair were recorded as equity in earnings of foreign affiliate.

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 home heating oil retailers and diesel fuel and gasoline resellers. Our commercial customers include federal and state agencies, municipalities, regional transit authorities, large industrial companies, hospitals and educational institutions. For the three months ended September 30, 2013 and 2012, we sold approximately 308.1 million and 208.8 million gallons of refined products, respectively. For the three months ended September 30, 2013 and 2012, our refined products segment accounted for 67% and 65% of our adjusted gross margin, respectively. For the nine months ended September 30, 2013 and 2012, we sold approximately 1.1 billion and 810.9 million gallons of refined products, respectively. For the nine months ended September 30, 2013 and 2012, our refined products segment accounted for 59% and 56% of our adjusted gross margin, respectively.

We also purchase, sell and distribute natural gas to more than 5,000 commercial and industrial customer locations across 10 states in the Northeast and Mid-Atlantic. We purchase the natural gas we sell from natural gas producers and trading companies. For the three months ended September 30, 2013 and 2012, we sold 10.0 Bcf and 9.8 Bcf of natural gas, respectively. For the three months ended September 30, 2013 and 2012, our natural gas segment accounted for 12% and 9% of our adjusted gross margin, respectively. For the nine months ended September 30, 2013 and 2012, we sold 38.3 Bcf and 35.3 Bcf of natural gas, respectively. For the nine months ended September 30, 2013 and 2012, our natural gas segment accounted for 22% and 19% of our adjusted gross margin, respectively.

Our materials handling business is a fee-based business and is generally conducted under multi-year agreements. We offload, store and/or prepare for delivery a variety of customer-owned products, including asphalt, clay slurry, salt, gypsum, coal, petroleum coke, caustic soda, tallow, pulp and heavy equipment. For the three months ended September 30, 2013, we offloaded, stored and/or prepared for delivery 0.5 million short tons of products and 54.5 million gallons of liquid materials. For the three months ended September 30, 2012, we offloaded, stored and/or prepared for delivery 0.6 million short tons of products and 61.7 million gallons of liquid materials. For the three months ended September 30, 2013 and 2012, our materials handling segment accounted for 19% and 25% of our adjusted gross margin, respectively. For the nine months ended September 30, 2013, we offloaded, stored and/or prepared for delivery 1.6 million short tons of products and 177.0 million gallons of liquid materials. For the nine months ended September 30, 2012, we offloaded, stored and/or prepared for delivery 1.9 million short tons of products and 186.5 million gallons of liquid materials. For the nine months ended September 30, 2013 and 2012, our materials handling segment accounted for 16% and 24% of our adjusted gross margin, respectively.

Our other operations segment includes the marketing and distribution of coal conducted in our South Portland and Portland, Maine terminals and certain commercial trucking activity performed by Kildair. For the three months ended September 30, 2013 and 2012, our other operations segment accounted for approximately 2% and 1% of our adjusted gross margin, respectively. For the nine months ended September 30, 2013 and 2012, our other operations segment accounted for approximately 3% and 1% of our adjusted gross margin, respectively.

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

Recent Developments

Initial Public Offering

On October 30, 2013, we completed the initial public offering of 8,500,000 common units (the “IPO”), representing a 42.2% limited partnership interest in us at an initial public offering price of $18.00 per unit. Total proceeds of the sale of the common units were $153.0 million before underwriting discounts and commissions, the structuring fee and estimated offering expenses.

On October 30, 2013, in connection with the closing of the IPO, we entered into a contribution, conveyance and assumption agreement, pursuant to which, among other things, Sprague Holdings conveyed to us all of the ownership interests in our Predecessor, in exchange for (a) 1,571,970 common units, representing a 7.8% limited partner interest in the Partnership, (b) 10,071,970 subordinated units, representing a 50% limited partner interest in the Partnership, (c) all of the equity interests in the Partnership classified as incentive distribution rights under the amended and restated agreement of limited partnership of Sprague Resources, and (d) the right to receive the deferred issuance and distribution (as defined in the Contribution Agreement). See Note 10 – “Subsequent Events.” After the IPO, Axel Johnson owns 1,571,970 common units and 10,071,970 subordinated units, representing a combined 57.8% interest.

In connection with the IPO, the following transactions, among other things, occurred:

•

Axel Johnson contributed to Sprague Holdings all of the ownership interests in Sprague Operating Resources LLC;

•

Sprague Operating Resources LLC distributed to Sprague Holdings or a wholly owned subsidiary of Sprague Holdings certain assets and liabilities that will not be a part of our initial assets, including:

•

an aggregate of $140.4 million (which consisted of $130.4 million of accounts receivable and $10.0 million of cash;

•

the 100% equity interest in Sprague Energy Canada Ltd., which owns an asphalt and residual fuel oil marketing and storage company with 3.2 million barrels of storage capacity located in Quebec, Canada, referred to herein as Kildair;

•

terminal assets and liabilities associated with terminals located in New Bedford, Massachusetts, Portsmouth, New Hampshire and Bucksport, Maine; property located in Oceanside, New York and certain corporate assets; and

•

other long-term debt of $64.5 million.

•

Sprague Holdings contributed to the Partnership all of the membership interests in Sprague Operating Resources LLC, the operating company, in exchange for 1,571,970 common units, 10,071,970 subordinated units, the incentive distribution rights, which entitle the holder to increasing percentages, up to a maximum of 50.0%, of the cash we distribute in excess of $0.474375 per unit per quarter as described under “Our Cash Distribution Policy and Restrictions on Distributions” in our Prospectus;

•

We issued and sold 8,500,000 common units to the public representing an aggregate 42.2% limited partner interest;

•

We entered into a new credit agreement, consisting of a working capital facility of up to $750.0 million and an acquisition facility of up to $250.0 million, as described in “Part I, Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations –Liquidity and Capital Resources—New Credit Agreement”;

•

We applied the net proceeds from the issuance and sale of 8,500,000 common units as a reduction of the borrowings under our credit facility; and

•

We entered into an omnibus agreement, a services agreement and a terminal operating agreement with respect to the New Bedford, Massachusetts terminal with Sprague Holdings and/or certain of its affiliates, each as described in “Certain Relationships and Related Party Transactions—Agreements Governing the Transactions” in our Prospectus.

Omnibus Agreement

On October 30, 2013, in connection with the closing of the IPO, we entered into an omnibus agreement with the Parent, Sprague Holdings and our general partner (the “Omnibus Agreement”). The Omnibus Agreement addresses the agreement of the Parent to offer to us, and to cause the Parent’s controlled affiliates to offer to us, opportunities to acquire certain businesses and assets and the obligation of Sprague Holdings to indemnify us for certain liabilities. Pursuant to the Omnibus Agreement, the Parent agreed to continue to provide credit support to Sprague Resources, consistent with past practice, through December 31, 2016, if and to the extent such services are necessary and reasonable, and we agreed to use our commercially reasonable efforts to reduce, and eventually eliminate, the need for trade credit support from the Parent. The Omnibus Agreement may be terminated (other than with respect to the indemnification provisions) by any party to the Omnibus Agreement in the event that the Parent, directly or indirectly, owns less than 50% of the voting equity power of our general partner.

Services Agreement

On October 30, 2013, in connection with the closing of the IPO, we, our general partner, Sprague Holdings and Sprague Energy Solutions, Inc., a Delaware corporation and a wholly owned subsidiary of the Predecessor (“Sprague Solutions”), entered into an operational services agreement (the “Services Agreement”). Pursuant to the Services Agreement, the General Partner will provide certain general and administrative and operational services to us and our subsidiaries, Sprague Solutions and Sprague Holdings, and we will reimburse the General Partner for all costs and expenses incurred in connection with providing such services to us. The Services Agreement does not limit the amount that may be reimbursed or paid by us to our general partner. The initial term of the Services Agreement will expire on October 30, 2018. The Services Agreement will automatically renew at the end of the initial term for successive one-year terms until terminated in accordance with the terms thereof. The Services Agreement does not limit the ability of the officers and employees of our general partner to provide services to other affiliates of Sprague Holdings or unaffiliated third parties.

Terminal Operating Agreement

On October 30, 2013, in connection with the closing of the IPO, Sprague Massachusetts Properties LLC, a Delaware limited liability company and a wholly owned subsidiary of Sprague Holdings (“Sprague Massachusetts”) and the OLLC (our operating company) entered into an exclusive terminal operating agreement (the “Terminal Operating Agreement”) with respect to the terminal in New Bedford, Massachusetts owned by Sprague Massachusetts. Pursuant to the Terminal Operating Agreement, the OLLC has the exclusive use and operation of, and retains title to all of the refined products stored at, the New Bedford terminal owned by Sprague Massachusetts in exchange for a monthly fee to Sprague Massachusetts. The initial term of the Terminal Operating Agreement will expire on October 30, 2018. The Terminal Operating Agreement will terminate upon 60 days’ written notice from Sprague Holdings or Sprague Massachusetts in the event that Sprague Holdings or Sprague Massachusetts determines that termination is necessary to facilitate the sale or development of the New Bedford terminal. The New Bedford terminal is subject to a purchase and sale agreement pursuant to which a third party may acquire the terminal from Sprague Massachusetts. Subject to certain conditions, such acquisition may be consummated on or before January 5, 2016. If such acquisition is consummated, the Terminal Operating Agreement will automatically terminate.

New Credit Agreement

On October 30, 2013, in connection with the closing of the IPO, we entered into a new revolving credit agreement (the “New Credit Agreement”). The New Credit Agreement will mature on October 30, 2018. There are two revolving credit facilities under the New Credit Agreement:

•

A working capital facility of up to $750.0 million to be used for working capital loans and letters of credit in the principal amount equal to the lesser of our borrowing base and $750.0 million; and

•

An acquisition facility of up to $250.0 million to be used for loans and letters of credit to fund capital expenditures and acquisitions.

We and each of our subsidiaries are guarantors of all obligations under the New Credit Agreement. All obligations under the New Credit Agreement are secured by substantially all of our assets. See “Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources—New Credit Agreement” for additional information regarding the New Credit Agreement.

Long-Term Incentive Plan

Our general partner adopted the Sprague Resources LP 2013 Long-Term Incentive Plan (the “LTIP”) effective immediately prior to the effective date of the IPO, for the benefit of employees, consultants and directors of our general partner and its affiliates, who provide services to our general partner or an affiliate. The LTIP provides us with the flexibility to grant unit options, restricted units, phantom units, unit appreciation rights, cash awards, distribution equivalent rights, substitute awards, and other unit-based awards, or any combination of the foregoing.

The LTIP will expire upon the earlier of (i) its termination by the board of directors of our general partner, (ii) the date common units are no longer available under the LTIP for grants or (iii) the tenth anniversary of the date the LTIP was approved by our general partner.

Non-GAAP Financial Measures

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

How Management Evaluates Our Results of Operations

Our management uses a variety of financial and operational measurements to analyze our performance. These measurements include: (1) gross margin, (2) operating expenses, (3) selling, general and administrative (or SG&A) expenses, (4) heating degree days and (5) adjusted gross margin and adjusted EBITDA.

Gross Margin

We view gross margin as an important performance measure of the core profitability of our operations. We review gross margin data monthly for consistency and trend analysis. We define gross margin as net sales minus costs of products sold. Net sales include sales of refined products and natural gas and the fees associated with the provision of materials handling services. Product costs include the cost of acquiring the refined products and natural gas that we sell and all associated costs to transport such products to the point of sale, as well as costs that we incur in providing materials handling services to our customers.

Operating Expenses

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

Selling, General and Administrative Expenses

Our SG&A expenses include employee salaries and benefits, pension and 401(k) plan expenses, discretionary bonus, marketing costs, corporate overhead, professional fees, information technology and office space expenses. We believe that our SG&A expenses will increase as a result of our becoming a publicly traded partnership.

Heating Degree Days

A “degree day” is an industry measurement of temperature designed to evaluate energy demand and consumption. Degree days are based on how much the average temperature departs from a human comfort level of 65°F. Each degree of temperature above 65°F is counted as one cooling degree day, and each degree of temperature below 65°F is counted as one heating degree day. Degree days are accumulated each day over the course of a year and can be compared to a monthly or a long-term average, or normal, to see if a month or a year was warmer or cooler than usual. Degree days are officially observed by the National Weather Service and officially archived by the National Climatic Data Center. For purposes of evaluating our results of operations, we use the normal heating degree day amount as reported by the NOAA/National Weather Service for the New England oil home heating region over the period of 1981-2010.

EBITDA

We define EBITDA as net income before interest, income taxes, depreciation and amortization. EBITDA is used as a supplemental financial measure by external users of our financial statements, such as investors, commercial banks, trade suppliers and research analysts, to assess:

•

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

•

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

•

The viability of acquisitions and capital expenditure projects.

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

Adjusted Gross Margin and Adjusted EBITDA

Management utilizes adjusted gross margin and adjusted EBITDA to assist it in reviewing our financial results and managing our business segments. We define adjusted gross margin as gross margin decreased by total commodity derivative gains and losses included in net income (loss) and increased by realized commodity derivative gains and losses included in net income (loss), in each case with respect to refined products and natural gas inventory and natural gas transportation contracts. We define adjusted EBITDA as EBITDA decreased by total commodity derivative gains and losses included in net income (loss) and increased by realized commodity derivative gains and losses included in net income (loss), in each case with respect to refined products and natural gas inventory and natural gas transportation contracts. 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 supplemental financial measures used by management to describe our operations and economic performance to commercial banks, trade suppliers and other credit suppliers, 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, income from operations, cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP.

Hedging Activities

We economically hedge our inventory within the guidelines set in our risk management policy. In a rising commodity price environment, the market value of our inventory will generally be higher than the cost of our inventory. For GAAP purposes, we are required to value our inventory at the lower of cost or market, or LCM. The hedges on this inventory will lose value as the value of the underlying commodity rises, creating hedging losses. Because we do not utilize hedge accounting, GAAP requires us to record those hedging losses in our statement of operations. In contrast, in a declining commodity price market we generally incur hedging gains. GAAP requires us to record those hedging gains in our statement of operations. The refined products inventory market valuation is calculated daily using independent bulk market price assessments from major pricing services (either Platts or Argus). These third-party price assessments are based in New York Harbor, or NYH, with our inventory values determined after adjusting the NYH prices to the various inventory locations by adding expected cost differentials (primarily freight) compared to a NYH supply source. Our natural gas inventory is limited, with the valuation updated monthly based on the volume and prices at the corresponding inventory locations. The prices are based on the monthly Inside FERC, or IFERC, assessments published by Platts near the beginning of the following month. A direct IFERC assessment is used when available, with the value for other inventory locations based on adding a location (basis) differential to the price assessment of a more liquid location.

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 prices are based on trader assessed quotes which represent observable transactions in the market place.

As described above, pursuant to GAAP, we value our commodity derivative hedges at the end of each reporting period based on current commodity prices and record hedging gains or losses, as appropriate. Also as described above, and pursuant to GAAP, our refined products and natural gas inventory and natural gas transportation contract rights, to which the commodity derivative hedges relate, are not marked to market for the purpose of recording gains or losses. In measuring our operating performance, we rely on our GAAP financial results, but we also find it useful to adjust those numbers to only show the impact of hedging gains and losses actually realized in the period being reviewed. By making such adjustments, as reflected in adjusted gross margin and adjusted EBITDA, we believe that we are able to more closely align hedging gains and losses to the period in which the revenue from the sale of inventory and income from transportation contracts relating to those hedges is realized.

The results of operations in this “Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations” section are supplemented with adjusted gross margin and adjusted EBITDA financial information.

Recent Trends and Outlook

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

•

New, stricter environmental laws and regulations are increasing the compliance cost of terminal operations, which could adversely affect our results of operations and financial condition. Our operations are subject to federal, state and local laws and regulations regulating product quality specifications and other environmental matters. The trend in environmental regulation is towards more restrictions and limitations on activities that may affect the environment. We try to anticipate future regulatory requirements that might be imposed and to plan accordingly to remain in compliance with changing environmental laws and regulations and to minimize the costs of such compliance. However, there can be no assurances as to the timing and type of such changes in existing laws or the promulgation of new laws or the amount of any required expenditures associated therewith.

•

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

•

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

•

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

Factors that Impact our Business

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

•

Seasonality and weather conditions. Our financial results are impacted by seasonality in our businesses and are generally better during the winter months, primarily because a material part of our business consists of supplying home heating oil, residual fuel oil and natural gas for space heating purposes during the winter. For example, over the 36-month period ended September 30, 2013, we generated an average of approximately 69% of our total home heating oil and residual fuel oil net sales during the months of November through March. In addition, weather conditions, particularly during these five months, have a significant impact on the demand for our products. Warmer-than-normal temperatures during these months in our areas of operations can decrease the total volume of home heating oil, residual fuel oil and natural gas we sell and the gross margins realized on those sales, whereas colder-than-normal temperatures increase demand for those products and the associated gross margins.

•

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

•

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

•

Absolute price increases can lead to reduced demand, increased credit risk, higher interest costs and temporarily reduced margins. Refined product prices have risen due to, among other things, investor interest in using commodities as an inflation hedge, U.S. dollar weakness and supply and demand fundamentals. For example, NYMEX heating oil (HO) contracts have risen from approximately $2.00 per gallon in December 2009 to over $3.16 per gallon in September 2013. As refined product prices rise, we generally experience reduced demand as customers engage in conservation efforts. We also experience a higher level of credit risk from our customers. In addition, our working capital requirements for holding inventory and financing receivables increase with higher price levels, while gross margin levels may stay relatively constant for a period of time due to competitive pressures.

•

Interest rates could rise. Since mid-2009, the credit markets have been experiencing near-record lows in interest rates. As the overall economy strengthens, it is expected that monetary policy will tighten, resulting in higher interest rates to counter possible inflation. This could affect our ability to access the debt capital markets to the extent we may need to in the future to fund our growth. In addition, interest rates could be higher than current levels, causing our financing costs to increase accordingly. During the 24 months ended September 30, 2013, we hedged approximately 48% of our floating-rate debt with fixed-for-floating interest rate swaps. Although higher interest rates could limit our ability to raise funds in the debt capital markets, we expect to remain competitive with respect to acquisitions and capital projects, as our competitors would face similar circumstances. As with other yield-oriented securities, our unit price is impacted by the level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank related yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our common units, and a rising interest rate environment could have an adverse impact on our unit price and our ability to issue additional equity to make acquisitions, reduce debt or for other purposes.

Comparability of our Financial Statements

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

Our Predecessor’s historical results of operations include the results of operations of Kildair, an asphalt and residual fuel oil marketing and storage business (in which our Predecessor had a 50% interest prior to, and is a consolidated wholly-owned subsidiary as of, October 1, 2012) that was owned by our Predecessor and was not contributed to us in connection with the IPO. From October 2007 through September 30, 2012, the investment in Kildair was accounted for using the equity method of accounting and our Predecessor’s share of its results were recorded as equity in net (loss) income of foreign affiliate. Demand for Kildair’s asphalt business is generally higher during the period of April through September than during the period of November through March. The table below provides certain financial information relating to the operations of Kildair, since Kildair’s results of operations are included in the financial statements of our Predecessor. Kildair is not part of our assets following the completion of the IPO. Accordingly, Kildair’s results of operations will not be included in our results of operation after October 30, 2013, the date on which we completed our IPO.


	Kildair
	Three Months Ended September 30, 2013		Nine Months Ended September 30, 2013
	(unaudited) ($ in thousands)
Net sales	$	194,146	$	455,731
Gross margin	$	9,217	$	18,551
Adjusted gross margin	$	9,217	$	18,551

Our results of operations can be impacted by swings in commodity prices, primarily in refined products and natural gas. We use economic hedges to minimize the impact of changing prices on refined products and natural gas inventory. As a result, commodity price increases at the end of a year can create lower gross margins as the economic hedges, or derivatives, for such inventory may lose value, whereas an increase in the value of such inventory is ignored for GAAP financial reporting purposes because inventory is recorded at the lower of cost or market. For a more detailed discussion, please see “Part I, Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations—How Management Evaluates Our Results of Operations.”

We believe that SG&A will increase by approximately $2.1 million annually as a result of our becoming a publicly traded partnership following the IPO. These expenses include increased accounting support services, filing annual and quarterly reports with the SEC, increased audit fees, investor relations, directors’ fees, directors’ and officers’ insurance, legal fees, stock exchange listing fees and registrar and transfer agent fees; however, such expenses are not reflected in our historical financial statements. Our financial statements following the completion of our IPO on October 30, 2013 will reflect the impact of these increased expenses, which will affect the comparability of our financial statements with periods prior to the completion of the IPO.

Results of Operations

The following table presents our volume, net sales, gross margin and adjusted gross margin by segment, as well our adjusted EBITDA and information on weather conditions, for the three and nine months ended September 30, 2013 and 2012. For a description of how we define the non-GAAP financial measure EBITDA, adjusted EBITDA and adjusted gross margin, see “Part I, Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations – How Management Evaluates Our Results of Operations.”


	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
	($ and volumes in thousands)
Volumes:
Refined products (gallons)		308,135			208,782			1,073,167			810,936
Natural gas (MMBtus)		9,983			9,820			38,312			35,324
Materials handling (short tons)		538			644			1,616			1,931
Materials handling (gallons)		54,474			61,656			177,030			186,522
Other operations (short tons)		34			32			105			103

Net Sales:
Refined products	$	879,691		$	651,030		$	3,148,743		$	2,543,622
Natural gas		49,623			43,105			222,704			167,815
Materials handling		7,185			7,713			21,713			23,673
Other operations		3,776			1,845			13,888			6,189

Total net sales	$	940,275		$	703,693		$	3,407,048		$	2,741,299


Gross Margin:
Refined products	$	26,119		$	7,453		$	82,902		$	47,604
Natural gas		(8,599	)		(2,278	)		16,639			10,728
Materials handling		7,181			7,660			21,700			23,464
Other operations		1,000			369			3,369			1,237

Total gross margin	$	25,701		$	13,204		$	124,610		$	83,033


Adjusted Gross Margin:
Refined products	$	25,447		$	19,692		$	78,593		$	55,691
Natural gas		4,415			2,773			28,401			18,356
Materials handling		7,181			7,660			21,700			23,464
Other operations		1,000			369			3,369			1,237

Total adjusted gross margin	$	38,043		$	30,494		$	132,063		$	98,748


Calculation of Adjusted Gross Margin:
Total gross margin	$	25,701		$	13,204		$	124,610		$	83,033
Deduct: total commodity derivative (gains) losses included in net income (loss)(1)		23,051			31,086			21,200			26,759
Add: realized commodity derivative gains (losses) included in net income (loss)(1)		(10,709	)		(13,796	)		(13,747	)		(11,044	)

Total adjusted gross margin (2)	$	38,043		$	30,494		$	132,063		$	98,748


	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
	($ and volumes in thousands)

Reconciliation to Net (Loss) Income:

Gross margin	$	25,701		$	13,204		$	124,610		$	83,033

Operating costs and expenses not allocated to operating segments:
Operating expenses		12,844			10,287			40,444			32,393
Selling, general and administrative		12,633			9,870			39,689			32,370
Depreciation and amortization		4,034			2,493			12,471			7,458

Total operating costs and expenses		29,511			22,650			92,604			72,221

Operating (loss) income		(3,810	)		(9,446	)		32,006			10,812
Loss on impairment of assets		—			—			—			(529	)
Other (expense) income		(215	)		(134	)		601			(134	)
Interest income		261			130			521			438
Interest expense		(7,207	)		(4,855	)		(21,846	)		(16,273	)
Income tax benefit (provision)		4,560			6,908			(6,078	)		3,203
Equity in net loss of foreign affiliate		—			(3,361	)		—			(1,009	)

Net (loss) income	$	(6,411	)	$	(10,758	)	$	5,204		$	(3,492	)


Reconciliation of EBITDA to net (loss) income:
Net (loss) income	$	(6,411	)	$	(10,758	)	$	5,204		$	(3,492	)
Add/(deduct):
Interest expense, net		6,946			4,725			21,325			15,835
Tax (benefit) expense		(4,560	)		(6,908	)		6,078			(3,203	)
Depreciation and amortization		4,034			2,493			12,471			7,458

EBITDA (2)	$	9		$	(10,448	)	$	45,078		$	16,598

Deduct: total commodity derivative (gains) losses included in net income (loss)(1)		23,051			31,086			21,200			26,759
Add: realized commodity derivative gains (losses) included in net income (loss)(1)		(10,709	)		(13,796	)		(13,747	)		(11,044	)
Add/(deduct): Bio-fuel excise tax credits (3)		—			601			(5,021	)		3,693

Adjusted EBITDA (2)	$	12,351		$	7,443		$	47,510		$	36,006

Other Data:
Normal heating degree days(4)		204			204			4,432			4,470
Actual heating degree days		211			163			4,288			3,699
Variance from normal heating degree days		3.4	%		(20.1	)%		(3.2	)%		(17.2	)%
Variance from prior period actual heating degree days		29.4	%		40.5	%		15.9	%		(15.2	)%

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

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

(3)

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

(4)	As reported by the NOAA/National Weather Service for the New England oil home heating region over the period of 1981-2010.

Three Months Ended September 30, 2013 Compared to Three Months Ended September 30, 2012

Our results of operations for the three months ended September 30, 2013 reflect increasing sales volumes, net sales and unit gross margin in our refined products segment, increasing sales volumes and net sales and decreasing unit gross margin in our natural gas segment and decreasing sales volumes, net sales and gross margin in our materials handling segment.

Adjusted gross margin for the three months ended September 30, 2013 reflects decreasing adjusted unit gross margin for refined products and increasing adjusted unit gross margin for natural gas.


	Three Months Ended September 30,						Increase/(Decrease)
	2013			2012			$			%
	(in thousands, except unit gross margin and adjusted unit gross margin)
Volumes:
Refined products (gallons)		308,135			208,782			99,353			48	%
Natural gas (MMBtus)		9,983			9,820			163			2	%
Materials handling (short tons)		538			644			(106	)		(16	)%
Materials handling (gallons)		54,474			61,656			(7,182	)		(12	)%
Other (short tons)		34			32			2			6	%

Net Sales:
Refined products	$	879,691		$	651,030		$	228,661			35	%
Natural gas		49,623			43,105			6,518			15	%
Materials handling		7,185			7,713			(528	)		(7	)%
Other		3,776			1,845			1,931			105	%

Total net sales	$	940,275		$	703,693		$	236,582			34	%

Gross Margin:
Refined products	$	26,119		$	7,453		$	18,666			250	%
Natural gas		(8,599	)		(2,278	)		(6,321	)		(277	%)
Materials handling		7,181			7,660			(479	)		(6	)%
Other		1,000			369			631			171	%

Total gross margin	$	25,701		$	13,204		$	12,497			95	%

Unit Gross Margin:
Refined products	$	0.085		$	0.036		$	0.049			136	%
Natural gas	$	(0.861	)	$	(0.232	)	$	(0.629	)		(271	%)

Adjusted Gross Margin:
Refined products	$	25,447		$	19,692		$	5,755			29	%
Natural gas		4,415			2,773			1,642			59	%
Materials handling		7,181			7,660			(479	)		(6	)%
Other		1,000			369			631			171	%


Total adjusted gross margin	$	38,043		$	30,494		$	7,549			25	%

Adjusted Unit Gross Margin:
Refined products	$	0.083		$	0.094		$	(0.011	)		(12	)%
Natural gas	$	0.442		$	0.282		$	0.160			57	%

Refined Products

Refined products net sales were $879.7 million and $651.0 million for the three months ended September 30, 2013 and 2012, respectively. Excluding Kildair’s operations, net sales of $191.5 million for the three months ended September 30, 2013, the refined products net sales increase of $37.2 million, or 6%, was driven by higher refined products sales volumes. Excluding Kildair’s operations, sales volumes of 80.8 million gallons for the three months ended September 30, 2013, refined products sales volumes were 227.3 million gallons and 208.8 million gallons for the three months ended September 30, 2013 and 2012, respectively. Distillate sales volumes increased 19.3 million gallons, or 16%, period over period due to the acquisition of the Bridgeport, CT terminal and additional market share gains. Gasoline sales volumes decreased by approximately 2.2 million gallons, or 3%, as some of our competitors were more aggressive in reducing their pricing as a result of higher ethanol RIN values (RIN is a renewable identification number associated with government-mandated renewable fuel standards). Residual fuel oil sales volumes increased 1.4 million gallons, or 11%, largely a result of a sizable spot sale into the power generation sector. The average refined products selling price per gallon was 8% lower for the three months ended September 30, 2013 as compared to the same period in 2012.

Excluding Kildair’s operations, gross margin and adjusted gross margin of $8.5 million for the three months ended September 30, 2013, refined products gross margin was $17.6 million and $7.5 million for the three months ended September 30, 2013 and 2012, respectively. Refined products adjusted gross margin was $16.9 million and $19.7 million for the three months ended September 30, 2013 and 2012, respectively. For the three months ended September 30, 2013 and 2012, refined products adjusted gross margin was $0.7 million lower and $12.2 million higher than refined products gross margin due to changes in the difference between refined products total commodity derivative gains and losses and refined products realized commodity derivative gains and losses, respectively.

The refined products adjusted gross margin decrease of $2.8 million, or 14%, was due to lower unit margins on refined products sales. Lower gasoline margins were a result of aggressive pricing by some of our competitors with renewable volume obligations seeking to capture higher ethanol RIN values. Distillate and residual fuel unit margins were also down, due largely to lower returns associated with supply balancing and hedging activities.

Natural Gas

Natural gas net sales were $49.6 million and $43.1 million for the three months ended September 30, 2013 and 2012, respectively. The natural gas sales increase of $6.5 million, or 15%, was driven by higher commodity prices as the average natural gas price per MMBtu was approximately 13% higher. Natural gas sales volumes increased by 2% for the three months ended September 30, 2013 as compared to the same period in 2012.

Natural gas gross margin was $(8.6) million and $(2.3) million for the three months ended September 30, 2013 and 2012, respectively. Natural gas adjusted gross margin was $4.4 million and $2.8 million for the three months ended September 30, 2013 and 2012, respectively. Natural gas adjusted gross margin was $13.0 million and $5.1 million higher than natural gas gross margin for the three months ended September 30, 2013 and 2012, respectively, due to changes in the difference between natural gas total commodity derivative gains and losses and natural gas realized commodity derivative gains and losses.

The natural gas adjusted gross margin increase of $1.6 million, or 59%, was primarily due to the continuing transition of our customer base towards smaller commercial and industrial end users, as well as the optimization of transportation assets and storage utilization.

Materials Handling

Materials handling net sales were $7.2 million and $7.7 million for the three months ended September 30, 2013 and 2012, respectively. The materials handling net sales decrease of $0.5 million, or 7%, was primarily due to a decrease in salt and windmill component handling activity for the three months ended September 30, 2013 as compared to the same period in 2012. These declines were partially offset by increased asphalt handling revenue.

The materials handling gross margin decrease of $0.5 million, or 6%, was primarily due to lower activity levels in salt and windmill component handling. The reduction in salt margins was largely a result of lower than usual activity during the three months ended September 30, 2013, as there remained substantial inventory in place coming into the quarter. This surplus of salt supply resulted in lower deliveries to our facilities. The reduction in windmill component handling activity was a result of customers deferring planned projects beyond 2013. An increase in asphalt revenue due to higher volumes with two key customers partially offset these declines.

Other Operations

Sales from our other operations were $3.8 million and $1.8 million for the three months ended September 30, 2013 and 2012, respectively, representing an increase of $2.0 million, or 105%. Of this increase, $2.6 million was due to the commercial trucking activities of Kildair. This was partially offset by lower coal marketing sales due to reduced coal prices for the three months ended September 30, 2013 as compared to the same period in 2012.

Gross margins from our other operations were $1.0 million and $0.4 million for the three months ended September 30, 2013 and 2012, respectively. The $0.6 million increase, or 171%, was primarily due to the commercial trucking activities of Kildair.

Nine Months Ended September 30, 2013 Compared to Nine Months Ended September 30, 2012

Our results of operations for the nine months ended September 30, 2013 reflect increasing sales volumes, net sales and unit gross margin in both our refined products and natural gas segments and decreasing sales volumes, net sales and gross margin in our materials handling segment.

Adjusted gross margin for the nine months ended September 30, 2013 reflects increasing adjusted unit gross margin for refined products and for natural gas.


	Nine Months Ended September 30,				Increase/(Decrease)
	2013		2012		$			%
	(in thousands, except unit gross margin and adjusted unit gross margin)
Volumes:
Refined products (gallons)		1,073,167		810,936		262,231			32	%
Natural gas (MMBtus)		38,312		35,324		2,988			8	%
Materials handling (short tons)		1,616		1,931		(315	)		(16	)%
Materials handling (gallons)		177,030		186,522		(9,492	)		(5	)%
Other (short tons)		105		103		2			2	%

Net Sales:
Refined products	$	3,148,743	$	2,543,622	$	605,121			24	%
Natural gas		222,704		167,815		54,889			33	%
Materials handling		21,713		23,673		(1,960	)		(8	)%
Other		13,888		6,189		7,699			124	%

Total net sales	$	3,407,048	$	2,741,299	$	665,749			24	%

Gross Margin:
Refined products	$	82,902	$	47,604	$	35,298			74	%
Natural gas		16,639		10,728		5,911			55	%
Materials handling		21,700		23,464		(1,764	)		(8	)%
Other		3,369		1,237		2,132			172	%

Total gross margin	$	124,610	$	83,033	$	41,577			50	%

Unit Gross Margin:
Refined products	$	0.077	$	0.059	$	0.018			31	%
Natural gas	$	0.434	$	0.304	$	0.130			43	%

Adjusted Gross Margin:
Refined products	$	78,593	$	55,691	$	22,902			41	%
Natural gas		28,401		18,356		10,045			55	%
Materials handling		21,700		23,464		(1,764	)		(8	)%
Other		3,369		1,237		2,132			172	%


Total adjusted gross margin	$	132,063	$	98,748	$	33,315			34	%

Adjusted Unit Gross Margin:
Refined products	$	0.073	$	0.069	$	0.004			6	%
Natural gas	$	0.741	$	0.520	$	0.221			43	%

Refined Products

Refined products net sales were $3.1 billion and $2.5 billion for the nine months ended September 30, 2013 and 2012, respectively. Excluding Kildair’s operations, net sales of $447.8 million for the nine months ended September 30, 2013, the refined products net sales increase of $157.3 million, or 6%, was driven primarily by higher refined products sales volumes. Excluding Kildair’s operations, sales volumes of 190.5 million gallons for the nine months ended September 30, 2013, refined products sales

volumes were 882.7 million gallons and 810.9 million gallons for the nine months ended September 30, 2013 and 2012, respectively. Distillate sales volumes increased 84.4 million gallons, or 15%, period over period, with a key factor being the colder weather conditions in the first three months of 2013, following the unseasonably warm weather experienced during the three months ended March 31, 2012. Gasoline sales volumes decreased by approximately 14.0 million gallons, or 7%, for the nine months ended September 30, 2013 as compared to the same period in 2012. This decrease occurred primarily during the three months ended June 30, 2013 when some of our competitors were more aggressive in reducing their pricing as a result of higher ethanol RIN values. Residual fuel oil sales volumes increased 1.4 million gallons, or 3%, for the nine months ended September 30, 2013 as compared to the same period in 2012. The average refined products selling price per gallon was 6% lower for the nine months ended September 30, 2013 as compared to the same period in 2012.

Excluding Kildair’s operations, gross margin and adjusted gross margin of $16.5 million for the nine months ended September 30, 2013, refined products gross margin was $66.5 million and $47.6 million for the nine months ended September 30, 2013 and 2012, respectively. Refined products adjusted gross margin was $62.1 million and $55.7 million for the nine months ended September 30, 2013 and 2012, respectively. For the nine months ended September 30, 2013 and 2012, refined products adjusted gross margin was $4.4 million lower and $8.1 million higher than refined products gross margin due to changes in the difference between refined products total commodity derivative gains and losses and refined products realized commodity derivative gains and losses, respectively.

The refined products adjusted gross margin increase of $6.5 million, or 12%, was primarily due to improved returns in distillates, in particular heating oil. Heating oil volumes and unit margins both improved substantially, partly due to the colder weather conditions for the three months ended March 31, 2013 as compared to the same period in 2012. The reinstatement of the federal bio-fuel excise tax credits in January 2013 also contributed to the improved returns. These gains were somewhat offset by one-time basis losses associated with the transition of the NYMEX HO futures contract to ULSD specifications starting with the May 2013 contract.

Natural Gas

Natural gas net sales were $222.7 million and $167.8 million for the nine months ended September 30, 2013 and 2012, respectively. The natural gas sales increase of $54.9 million, or 33%, was driven by higher commodity prices as the average natural gas marketing price per MMBtu was approximately 22% higher during the nine months ended September 30, 2013 as compared to the same period in 2012. The stronger natural gas price environment was due in part to the higher weather-driven demand during the three months ended March 31, 2013. Natural gas sales volumes increased 8% for the nine months ended September 30, 2013 as compared to the same period in 2012, with the colder weather in the first three months of 2013 being a contributing factor.

Natural gas gross margin was $16.6 million and $10.7 million for the nine months ended September 30, 2013 and 2012, respectively. Natural gas adjusted gross margin was $28.4 million and $18.4 million for the nine months ended September 30, 2013 and 2012, respectively. Natural gas adjusted gross margin was $11.8 million higher than natural gas gross margin for the nine months ended September 30, 2013 and $7.7 million higher than natural gas gross margin for the nine months ended September 30, 2012 due to changes in the difference between natural gas total commodity derivative gains and losses and natural gas realized commodity derivative gains and losses.

The natural gas adjusted gross margin increase of $10.0 million, or 55%, was primarily due to the continuing transition of our customer base towards smaller commercial and industrial end users, as well as additional margin generation due to optimization of transportation assets and storage utilization particularly during the volatile pricing period experienced in the first three months of 2013. In addition, higher sales volumes in the first three months of 2013 due to colder weather conditions contributed to the improvement.

Materials Handling

Materials handling net sales were $21.7 million and $23.7 million for the nine months ended September 30, 2013 and 2012, respectively. The materials handling net sales decrease of $2.0 million, or 8%, was primarily due to a decrease in dry bulk activities including salt, gypsum and petcoke. In addition, windmill component handling activities were substantially lower in the nine months ended September 30, 2013 compared to the same period in 2012. These decreases were partially offset by increased asphalt revenues over the same time periods due primarily to increased volumes by a major customer.

The materials handling gross margin decrease of $1.8 million, or 8%, was primarily due to a decrease in dry bulk activities including salt, gypsum and petcoke, with a reduction in windmill component handling also a contributor. The reduction in salt

margins was largely a result of higher than expected activity during 2012 and resultant customer inventory surplus. The reduction in gypsum margins was a combination of an increase/shift of handling activities by a key customer during 2012 and the short-term deferral of planned volumes by another. The lower petroleum coke margin was a result of the timing of shipments. Higher asphalt margins partially offset the declines in the other areas.

Other Operations

Sales from our other operations were $13.9 million and $6.2 million for the nine months ended September 30, 2013 and 2012, respectively, representing an increase of $7.7 million. Of this increase, $7.9 million was due to the commercial trucking activities of Kildair.

Gross margins from our other operations were $3.4 million and $1.2 million for the nine months ended September 30, 2013 and 2012, respectively, representing an increase of $2.2 million. Of this increase, $2.1 million was due to the commercial trucking activities of Kildair.

Operating Costs and Expenses

Three Months Ended September 30, 2013 Compared to Three Months Ended September 30, 2012


	Three Months Ended September 30,				Increase/(Decrease)
	2013		2012		$		%
	($ in thousands)
Operating expenses	$	12,844	$	10,287	$	2,557		25	%
Selling, general and administrative expenses	$	12,633	$	9,870	$	2,763		28	%
Depreciation and amortization	$	4,034	$	2,493	$	1,541		62	%

Operating Expenses. Operating expenses for the three months ended September 30, 2013 increased $2.6 million, or 25%, as compared to the three months ended September 30, 2012 primarily due to the inclusion of $2.3 million of Kildair’s operating expenses, which consisted primarily of terminal and trucking salaries and benefits, maintenance, utilities and other costs. Operating expenses increased by $0.7 million due to higher facility maintenance costs and decreased by $0.4 million due to lower energy costs (primarily due to natural gas boiler conversion projects).

Selling, General and Administrative Expenses. Selling, general and administrative expenses for the three months ended September 30, 2013, increased $2.8 million, or 28%, as compared to the three months ended September 30, 2012, primarily due to the inclusion of Kildair’s expenses of $1.2 million, which consisted primarily of salaries and benefits and other expenses, increased discretionary incentive compensation of $1.1 million as a result of higher earnings performance and increased fees for audit related services of $0.3 million.

Depreciation and Amortization. Depreciation and amortization for the three months ended September 30, 2013 increased $1.5 million, or 62%, as compared to the three months ended September 30, 2012. Of this increase $1.5 million was due to the inclusion of Kildair’s depreciation expense.

Nine Months Ended September 30, 2013 Compared to Nine Months Ended September 30, 2012


	Nine Months Ended September 30,				Increase/(Decrease)
	2013		2012		$		%
	($ in thousands)
Operating expenses	$	40,444	$	32,393	$	8,051		25	%
Selling, general and administrative expenses	$	39,689	$	32,370	$	7,319		23	%
Depreciation and amortization	$	12,471	$	7,458	$	5,013		67	%

Operating Expenses. Operating expenses for the nine months ended September 30, 2013 increased $8.1 million, or 25%, as compared to the nine months ended September 30, 2012 primarily due to the inclusion of $7.9 million of Kildair’s operating expenses, which consisted primarily of terminal and trucking salaries and benefits, maintenance, utilities and other costs. Operating expenses decreased by $0.9 million due to lower costs associated with third party fees related to materials handling operations and increased by $0.6 million due to higher facility maintenance costs and $0.5 million due to higher fringe benefit and insurance costs.

Selling, General and Administrative Expenses. Selling, general and administrative expenses for the nine months ended September 30, 2013, increased $7.3 million, or 23%, as compared to the nine months ended September 30, 2012, primarily due to the inclusion of Kildair’s expenses of $3.8 million, which consisted primarily of salaries and benefits and other expenses and increased discretionary incentive compensation of $3.7 million as a result of higher earnings performance.

Depreciation and Amortization. Depreciation and amortization for the nine months ended September 30, 2013 increased $5.0 million, or 67%, as compared to the nine months ended September 30, 2012. Of this increase $5.3 million was due to the inclusion of Kildair’s depreciation expense.

Interest Expense, Net and Equity in Net (Loss) Income of Foreign Affiliate

Three Months Ended September 30, 2013 Compared to Three Months Ended September 30, 2012


	Three Months Ended September 30,					Increase/(Decrease)
	2013		2012			$		%
	($ in thousands)
Interest expense, net	$	6,946	$	4,725		$	2,221		47	%
Equity in net loss of foreign affiliate	$	—	$	(3,361	)	$	3,361			*

Not meaningful

Interest Expense, net. Interest expense, net for the three months ended September 30, 2013 increased $2.2 million, or 47%, as compared to the three months ended September 30, 2012. Of this increase, $1.2 million was related to Kildair activity and $1.0 million was primarily due to higher average balances for acquisition related borrowings.

Equity in Net Loss of Foreign Affiliate. The equity in net loss of our Predecessor’s foreign affiliate for the three months ended September 30, 2012, was $3.4 million. For the year ended December 30, 2011 and through September 30, 2012, we recorded the activity of Kildair as an equity investment in a foreign affiliate. Kildair was fully consolidated by our Predecessor beginning on October 1, 2012.

Nine Months Ended September 30, 2013 Compared to Nine Months Ended September 30, 2012


	Nine Months Ended September 30,					Increase/(Decrease)
	2013		2012			$		%
	($ in thousands)
Interest expense, net	$	21,325	$	15,835		$	5,490		35	%
Equity in net loss of foreign affiliate	$	—	$	(1,009	)	$	1,009			*

Not meaningful

Interest Expense, net. Interest expense, net for the nine months ended September 30, 2013 increased $5.5 million, or 35%, as compared to the nine months ended September 30, 2012. Of this increase, $2.9 million was related to Kildair activity and $2.6 million was primarily due to higher average balances for acquisition related borrowings.

Equity in Net (Loss) Income of Foreign Affiliate. The equity in net loss of our Predecessor’s foreign affiliate for the nine months ended September 30, 2012, was $1.0 million. For the year ended December 30, 2011 and through September 30, 2012, we recorded the activity of Kildair as an equity investment in a foreign affiliate. Kildair was fully consolidated by our Predecessor beginning on October 1, 2012.

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 the new revolving credit agreement we entered into in connection with the closing of our IPO and potential future issuances of additional partnership interests or debt securities are our primary sources of liquidity. Because our Predecessor’s credit agreement had a maturity date of May 28, 2014, all amounts outstanding were classified as current as of September 30, 2013. At September 30, 2013, our Predecessor had a net working capital deficit of approximately $(81.5) million. As of September 30, 2013, the borrowing base under our Predecessor’s working capital facility was approximately $379.9 million, and our Predecessor had approximately $246.5 million (excluding $40.7 million of outstanding letters of credit) in outstanding borrowings, providing our Predecessor with approximately $92.7 million in undrawn borrowing capacity under the facility. As of September 30, 2013, our Predecessor had approximately $132.7 million in outstanding borrowings under our Predecessor’s acquisition facility, providing our Predecessor with approximately $42.3 million in undrawn borrowing capacity under the facility.

We enter our seasonal peak period during the fourth quarter of each year, during which inventory, accounts receivable and debt levels increase. As we move out of the winter season at the end of the first quarter of the following year, inventory is reduced, accounts receivable are collected and converted into cash and debt is paid down. During the twelve months ended September 30, 2013, the amount that our Predecessor had drawn under the working capital facility of our Predecessor’s credit agreement fluctuated from a low of approximately $176.8 million to a high of approximately $399.6 million.

In connection with the closing of the IPO, we entered into a new revolving credit agreement. The new revolving credit agreement matures on October 30, 2018 and consists of two revolving credit facilities: (1) a $750.0 million working capital facility and (2) a $250.0 million acquisition facility.

We believe that we will have sufficient liquid assets, cash flow from operations and borrowing capacity under our new 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.

Certain of our trade credit providers have historically required us to obtain trade credit support from Axel Johnson, and Axel Johnson has provided us with such support for our operations. As of September 30, 2013, Axel Johnson provided us with approximately $57.3 million of outstanding trade credit support. We believe that over a reasonable period following the completion of the IPO, we will be able to work with our trade creditors to reduce, and eventually eliminate, the need for trade credit support from Axel Johnson. Pursuant to the omnibus agreement that we entered into in connection with the closing of the IPO, we agreed to use our commercially reasonable efforts to reduce, and eventually eliminate, the need for trade credit support from Axel Johnson. In order to assist us with a smooth transition with our trade credit providers following the completion of the IPO, pursuant to such omnibus agreement, Axel Johnson agreed to provide us with trade credit support, consistent with past practice, through December 31, 2016, if and to the extent such trade credit support is necessary in the our reasonable judgment. We believe that the elimination of trade credit support from Axel Johnson after December 31, 2016 will not have a material adverse effect on our operations.

New Credit Agreement

In connection with the closing of our IPO on October 30, 2013, we entered into a new revolving credit agreement having the principal terms described below.

There are two revolving credit facilities under our new credit agreement:

•

A working capital facility of up to $750.0 million to be used for working capital loans and letters of credit in the principal amount equal to the lesser of our borrowing base and $750.0 million. Our borrowing base will be calculated as the sum of specified percentages of eligible cash collateral, eligible billed and unbilled accounts receivable, eligible inventory (reflecting hedged and unhedged positions), prepaid purchases, the net liquidating value of positions in futures accounts, eligible forward contract value, and letters of credit minus the amount of any reserves, other priority claims and owed swap amounts. Subject to certain conditions, the working capital facility may be increased by up to $200.0 million.

•

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

We and each of our subsidiaries, if not the borrower, will be a guarantor of all obligations under the new credit agreement. All obligations under our new credit agreement will be secured by substantially all of our assets and substantially all of the assets of our subsidiaries.

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

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

The specified margin for the acquisition facility under our new credit agreement will range from 2.00% to 2.25% for loans bearing interest at the Alternate Base Rate, and from 3.00% to 3.25% for loans bearing interest at the Eurodollar Rate and for letters of credit issued under the acquisition facility. In addition, we will incur a commitment fee on the unused portion of the acquisition facility at a rate ranging from 0.375% to 0.50% per annum. The specified margin and the commitment fee for the acquisition facility is calculated quarterly based upon our consolidated total leverage ratio.

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

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

•

Grant liens;

•

Make certain loans or investments;

•

Incur additional indebtedness or guarantee other indebtedness;

•

Sell our assets; or

•

Acquire another company.

Our new credit agreement also will contain financial covenants requiring us to maintain:

•

Minimum consolidated net working capital of $35.0 million;

•

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

•

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

•

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

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

•

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

•

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

•

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

•

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

•

A judgment default for monetary judgments exceeding $10.0 million;

•

A change of control as defined below;

•

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

•

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

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

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements.

Capital Expenditures

Our terminals require investments to expand, upgrade or enhance existing assets and to comply with environmental and operational regulations. Our capital requirements primarily consist of maintenance capital expenditures and expansion capital expenditures. Maintenance capital expenditures represent capital expenditures made to replace assets, or to maintain the long-term operating capacity of our assets or operating income. Examples of maintenance capital expenditures are expenditures required to maintain equipment reliability, terminal integrity and safety and to address environmental laws and regulations. Costs for repairs and minor renewals to maintain facilities in operating condition and that do not extend the useful life of existing assets will be treated as maintenance expenses as we incur them. Expansion capital expenditures are capital expenditures made to increase the long-term operating capacity of our assets or our operating income whether through construction or acquisition of additional assets. Examples of expansion capital expenditures include the acquisition of equipment and the development or acquisition of additional storage capacity, to the extent such capital expenditures are expected to expand our operating capacity or our operating income.

During the nine months ended September 30, 2013, we incurred a total of approximately $4.7 million in maintenance capital expenditures and we spent $12.4 million for expansion and/or upgrades of our terminals. We anticipate that future maintenance capital expenditures will be funded with cash generated by operations and that future expansion capital requirements will be provided through long-term borrowings or other debt financings and/or equity offerings.

Cash Flows


	Nine Months Ended September 30,
	2013			2012
	(in thousands)
Net cash provided by operating activities	$	149,928		$	223,292
Net cash used in investing activities	$	(35,739	)	$	(4,941	)
Net cash used in financing activities	$	(114,406	)	$	(223,754	)

Operating Activities

Net cash provided by operating activities for the nine months ended September 30, 2013 was approximately $149.9 million. Our cash flow from operations was driven by a decrease of $144.2 million due to a reduction in inventory volumes resulting from a weak market structure relating to heating oil and residual fuel oil and a decrease of $56.8 million in accounts receivable primarily related to lower commodity prices. The cash flow was partially offset by a decrease of $61.7 million in accounts payable and accrued liabilities primarily due to the timing of invoice payments for product purchases.

Net cash provided by operating activities for the nine months ended September 30, 2012 was approximately $223.3 million. Our cash flow from operations was driven by a decrease of $131.2 million due to a reduction in inventory volumes resulting from a weak heating oil and residual fuel oil market structure, a decrease of $94.8 million in accounts receivable primarily related to lower sales volumes and a decrease of $39.5 million in derivative instruments related to less customer demand for locking in fixed price forward commitments. The cash flow was partially offset by a decrease of $56.6 million in accounts payable and accrued liabilities, primarily due to timing of invoice payments for product purchases.

Investing Activities

Net cash used in investing activities for the nine months ended September 30, 2013 was approximately $35.7 million, and consisted primarily of $20.7 million related to the purchase of the Bridgeport terminal, $11.5 million related to expansion capital expenditures at our Kildair terminal for a crude oil storage and handling construction project and $5.6 million relating to capital expenditure projects at our other terminals.

Net cash used in investing activities for the nine months ended September 30, 2012 was approximately $5.0 million and primarily related to capital expenditure projects.

Financing Activities

Net cash used in financing activities for the nine months ended September 30, 2013 was approximately $114.4 million. During 2013, the net cash used in financing activities primarily resulted from $82.6 million of net payments under the credit agreement due to reduced financing needs as a result of lower inventory levels and accounts receivable balances. Other financing activities included a $40.0 million dividend to Axel Johnson Inc. and a $10.0 million contribution from Axel Johnson Inc. relating to the purchase of the Bridgeport terminal.

Net cash used in financing activities for the nine months ended September 30, 2012 was approximately $223.8 million. During 2012, the net cash used in financing activities primarily resulted from $221.0 million of net payments under the credit agreement due to reduced financing needs as a result of lower inventory levels and accounts receivable balances. Other financing activities included a $26.9 million dividend to Axel Johnson Inc. and borrowings of $25.0 million from a third party relating to the financing of the purchase of the remaining 50% of Kildair’s equity.

Impact of Inflation

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

Recent Accounting Pronouncements

In July 2013, the FASB issued ASU 2013-10, “Derivatives and Hedging (Topic 815)—Inclusion of the Fed Funds Effective Swap Rate (or Overnight Index Swap Rate) as a Benchmark Interest Rate for Hedge Accounting Purposes”. This amended guidance permits the Fed Funds Effective Swap Rate to be used as a U.S. benchmark interest rate for hedge accounting purposes. The amendments also remove the restriction on using different benchmark rates for similar hedges. The amendments apply to all entities that elect to apply hedge accounting of the benchmark interest rate. This amendment is effective for qualifying new or redesignated hedge relationships entered into after July 17, 2013. The adoption of this ASU is not expected to have a significant impact on our consolidated financial statements.

In February 2013, the FASB issued ASU No. 2013-02, “Reporting Amounts Reclassified Out of Accumulated Other Comprehensive Income,” which amends ASC 220, “Comprehensive Income.” The amended guidance requires entities to provide information about the amounts reclassified out of accumulated other comprehensive income by component. Additionally, entities are required to present, either on the face of the financial statements or in the notes, significant amounts reclassified out of accumulated other comprehensive income by the respective line items of net income. The amended guidance does not change the current requirements for reporting net income or other comprehensive income. We adopted ASU 2013-02 as of January 1, 2013 and it did not have a material impact on our consolidated financial statements.

In December 2011, the FASB issued ASU 2011-11, “Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities.” ASU 2011-11 requires an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. Entities are required to disclose both gross and net information about these instruments. ASU 2011-11 is effective for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual periods. We adopted ASU 2011-11 as of January 1, 2013 and it did not have a material impact on our consolidated financial statements, but did result in additional disclosure regarding fair value measurement.

Critical Accounting Policies and Estimates

“Part I, Item, 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations” discusses our Predecessor’s consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of these consolidated financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results may differ from these estimates under different assumptions or conditions.

These estimates are based on our knowledge and understanding of current conditions and actions that we may take in the future. Changes in these estimates will occur as a result of the passage of time and the occurrence of future events. Subsequent changes in these estimates may have a significant impact on our financial condition and results of operations and are recorded in the period in which they become known. We have identified the following estimates that, in our opinion, are subjective in nature, require the exercise of judgment and involve complex analysis: derivatives, inventories, goodwill, net sales and cost of products sold recognition.

The significant accounting policies and estimates that have been adopted and followed in the preparation of our Predecessor’s consolidated financial statements are detailed in Note 1—“Description of Business and Summary of Significant Accounting Policies” included in our Prospectus. 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. As discussed in Note 1, certain new financial accounting pronouncements have been issued which have already been reflected in the accompanying consolidated financial statements.

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

Commodity Price Risk

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

We hedge our refined products positions primarily with a combination of futures contracts that trade on the New York Mercantile Exchange, or NYMEX, and fixed-for-floating price swaps that are bilateral contracts that are traded “over-the-counter.” Although there are some notable differences between futures and the fixed-for-floating price swaps, both can provide a fixed price while the counterparty receives a price that fluctuates as market prices change. As indicated in the table below, we primarily use futures contracts to hedge light oil transactions and swaps contracts for residual fuel oils futures contracts. There are no residual fuel oil futures contracts that actively trade in the United States. Each of the financial instruments trade by month for many months forward, allowing us the ability to hedge future contractual commitments.


Product Group		Primary Financial Hedging Instrument
Gasolines		NYMEX RBOB futures contract
Distillates		NYMEX Ultra Low Sulfur Diesel futures contract
Residual Fuel Oils		New York Harbor 1% Sulfur Residual Fuel Oil Swaps

In addition to the financial instruments listed above, we sometimes 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 ICE with the prices based on the Henry Hub location near Erath, Louisiana. The Henry Hub is the most active natural gas trading location in the United States. Although we typically use swaps, there is also an actively traded NYMEX Henry Hub natural gas futures contract that we can use. We primarily use ICE basis swaps as the key financial instrument type to hedge our natural gas basis risk. Similar to the natural gas futures and ICE Henry Hub swaps, basis swaps for major locations trade actively for many months. These swaps are financially settled, typically using prices quoted by Platts.

We also directly hedge our price exposure in oil and natural gas physically by using forward purchases or sales.

The following table presents total realized and unrealized (losses) and gains on derivative instruments utilized for commodity risk management purposes. Such amounts are included in cost of products sold for the three and nine months ended September 30, 2013 and 2012:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012

Refined products contracts	$	(9,142	)	$	(25,679	)	$	2,921		$	(22,117	)
Natural gas contracts		(13,909	)		(5,407	)		(24,121	)		(4,642	)

Total	$	(23,051	)	$	(31,086	)	$	(21,200	)	$	(26,759	)

Substantially all of our commodity derivative contracts outstanding as of September 30, 2013 will settle prior to December 31, 2014.

Interest Rate Risk

We enter into interest rate swaps to manage exposures in changing interest rates. We swap the variable LIBOR interest rate payable under our credit agreement for fixed LIBOR interest rates. These interest rate swaps meet the criteria to receive cash flow hedge accounting treatment. Counterparties to our interest rate swaps are large multi-national banks and we do not believe there is a material risk of counterparty nonperformance. At September 30, 2013, the notional value of our cash flow hedges was composed of base notional amounts of $210.0 million expiring through 2015. Additionally, we may enter into seasonal swaps which are intended to manage our increase in borrowings during the winter, as a result of higher inventory and accounts receivable levels. Borrowings under our new credit agreement will bear interest, at our option, at a rate per annum equal to the Eurodollar Rate (which means the LIBOR Rate as determined from indices from the British Bankers Association) and the Alternate Base Rate which means the highest of (a) the prime rate of interest announced from time to time by the agent as its “Base Rate,” (b) 0.50% per annum above the Federal Funds Rate as in effect from time to time and (c) the Eurodollar Rate for 1-month LIBOR as in effect from time-to-time plus 1.00% per annum, depending on which facility is being used. During the two year period ended September 30, 2013, we hedged approximately 48% of our floating rate debt with fixed-for-floating interest rate swaps. We report unrealized gains and losses on the interest rate swaps as a component of accumulated other comprehensive gain or loss, net of taxes, which is reclassified to earnings as interest expense when payments are made. We expect to continue to utilize interest rate swaps to manage our exposure to LIBOR interest rates. We do not expect our entering into the new credit agreement to have any impact on our accounting for the existing interest rate swap agreements.

Derivative Instruments

The following tables present all of our financial assets and financial liabilities measured at fair value on a recurring basis as of September 30, 2013:


	As of September 30, 2013
	Fair Value Measurement		Quoted Prices in Active Markets Level 1		Significant Other Observable Inputs Level 2		Significant Unobservable Inputs Level 3
Financial assets:
Commodity exchange contracts	$	172	$	172	$	—	$	—
Commodity fixed forwards		39,317		—		39,317		—
Commodity swaps and options		579		—		579		—


Commodity derivatives		40,068		172		39,896		—
Currency swaps		240		—		240		—


Total	$	40,308	$	172	$	40,136	$	—


Financial liabilities:
Commodity fixed forwards	$	45,928	$	—	$	45,928	$	—
Commodity swaps and options		1,228		—		1,228		—


Commodity derivatives		47,156		—		47,156		—
Interest rate swaps		3,630		—		3,630		—


Total	$	50,786	$	—	$	50,786	$	—

Market and Credit Risk

The risk management activities for our refined products and natural gas segments involve managing exposures to the impact of market fluctuations in the price and transportation costs for commodities through the use of derivative instruments. The volatility of prices for energy commodities can be significantly influenced by market liquidity and changes in seasonal demand, weather conditions, transportation availability, and federal and state regulations. We monitor and manage our exposure to market risk on a daily basis in accordance with approved policies.

We maintain a control environment under the direction of our Chief Risk Officer through our risk management policy, processes and procedures, which our senior management has approved. Controls include volumetric, value at risk and stop loss limits on discretionary positions as well as contract term limits. Our Chief Risk Officer must approve the use of new instruments or new commodities. Risk limits are monitored and reported daily to senior management. Our risk management department also performs independent verifications of sources of fair values. These controls apply to all of our commodity risk management activities.

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

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

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

Item 4.

Controls and Procedures

Disclosure Controls and Procedures

Our management, with the participation of our Chief Executive Officer and our Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures as of September 30, 2013. The term “disclosure controls and procedures,” as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended, or the Exchange Act, means controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the company’s management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Based on the evaluation of our disclosure controls and procedures as of September 30, 2013, our Chief Executive Officer and Chief Financial Officer concluded that, as of such date, our disclosure controls and procedures were effective at the reasonable assurance level.

Internal Control Over Financial Reporting

There has not been any change in our internal controls over financial reporting (as defined by Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the three months ended September 30, 2013 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II - OTHER INFORMATION

Item 1.

Legal Proceedings

Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not a party to any litigation or governmental or other proceeding that we believe will have a material adverse impact on our consolidated financial condition or results of operations.

Item 1A.

Risk Factors

In addition to other information set forth in this report, you should carefully consider the factors discussed in “Risk Factors” included in our Prospectus, which could materially affect our business, financial condition or future results.

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

None.

Item 3.

Defaults Upon Senior Securities

None.

Item 4.

Mine Safety Disclosures

Not applicable.

Item 5.

Other Information

None.

Item 6.

Exhibits

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


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

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

10.1	—	Credit Agreement among Sprague Operating Resources LLC, as borrower, the several lenders parties thereto, JPMorgan Chase Bank, N.A., as administrative agent, and the co-collateral agents, the co-syndication agents and the co-documentation agents party thereto (incorporated by reference to Exhibit 10.1 of Sprague Resources Partners LP’s Current Report on Form 8-K filed November 5, 2013 (File No. 001-36137)).

10.2	—	Contribution, Conveyance and Assumption Agreement by and among Sprague Resources LP, Sprague Resources GP LLC, Axel Johnson Inc., Sprague International Properties LLC, Sprague Canadian Properties LLC, Sprague Resources Holdings LLC, Sprague Massachusetts Properties LLC and Sprague Operating Resources LLC (incorporated by reference to Exhibit 10.2 of Sprague Resources Partners LP’s Current Report on Form 8-K filed November 5, 2013 (File No. 001-36137)).

10.3	—	Omnibus Agreement by and among Axel Johnson Inc., Sprague Resources Holdings LLC, Sprague Resources LP and Sprague Resources GP LLC (incorporated by reference to Exhibit 10.3 of Sprague Resources Partners LP’s Current Report on Form 8-K filed November 5, 2013 (File No. 001-36137)).

10.4	—	Services Agreement by and among Sprague Resources GP LLC, Sprague Resources LP, Sprague Resources Holdings LLC and Sprague Energy Solutions Inc. (incorporated by reference to Exhibit 10.4 of Sprague Resources Partners LP’s Current Report on Form 8-K filed November 5, 2013 (File No. 001-36137)).

10.5	—	Terminal Operating Agreement by and between Sprague Massachusetts Properties LLC and Sprague Operating Resources LLC (incorporated by reference to Exhibit 10.5 of Sprague Resources Partners LP’s Current Report on Form 8-K filed November 5, 2013 (File No. 001-36137)).

10.6	—	Sprague Resources LP 2013 Long-Term Incentive Plan, effective as of October 28, 2013 (incorporated by reference to Exhibit 4.4 to Sprague Resources LP’s Registration Statement on Form S-8, filed on October 25, 2013 (File No. 333-191923)).

10.7	—	Form of Phantom Unit Award Agreement (incorporated by reference to Exhibit 10.8 to Sprague Resources LP’s Registration Statement on Form S-1, filed on September 24, 2013 (File No. 333-175826)).

10.8	—	Form of Restricted Unit Award Agreement (incorporated by reference to Exhibit 10.9 to Sprague Resources LP’s Registration Statement on Form S-1, filed on September 24, 2013 (File No. 333-175826)).

10.9	—	Form of Unit Award Letter (incorporated by reference to Exhibit 10.10 to Sprague Resources LP’s Registration Statement on Form S-1, filed on September 24, 2013 (File No. 333-175826)).

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

*	Not deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934 or otherwise subject to the liability of that section.

**	To be filed by amendment, in accordance with Rule 405(a)(2)(ii) of Regulation S-T.

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

		/s/ Gary A. Rinaldi
Date: November 27, 2013		Senior Vice President, Chief Operating Officer and Chief Financial Officer (Principal Financial Officer)

EXHIBIT INDEX


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

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

10.1	—	Credit Agreement among Sprague Operating Resources LLC, as borrower, the several lenders parties thereto, JPMorgan Chase Bank, N.A., as administrative agent, and the co-collateral agents, the co-syndication agents and the co-documentation agents party thereto (incorporated by reference to Exhibit 10.1 of Sprague Resources Partners LP’s Current Report on Form 8-K filed November 5, 2013 (File No. 001-36137)).

10.2	—	Contribution, Conveyance and Assumption Agreement by and among Sprague Resources LP, Sprague Resources GP LLC, Axel Johnson Inc., Sprague International Properties LLC, Sprague Canadian Properties LLC, Sprague Resources Holdings LLC, Sprague Massachusetts Properties LLC and Sprague Operating Resources LLC (incorporated by reference to Exhibit 10.2 of Sprague Resources Partners LP’s Current Report on Form 8-K filed November 5, 2013 (File No. 001-36137)).

10.3	—	Omnibus Agreement by and among Axel Johnson Inc., Sprague Resources Holdings LLC, Sprague Resources LP and Sprague Resources GP LLC (incorporated by reference to Exhibit 10.3 of Sprague Resources Partners LP’s Current Report on Form 8-K filed November 5, 2013 (File No. 001-36137)).

10.4	—	Services Agreement by and among Sprague Resources GP LLC, Sprague Resources LP, Sprague Resources Holdings LLC and Sprague Energy Solutions Inc. (incorporated by reference to Exhibit 10.4 of Sprague Resources Partners LP’s Current Report on Form 8-K filed November 5, 2013 (File No. 001-36137)).

10.5	—	Terminal Operating Agreement by and between Sprague Massachusetts Properties LLC and Sprague Operating Resources LLC (incorporated by reference to Exhibit 10.5 of Sprague Resources Partners LP’s Current Report on Form 8-K filed November 5, 2013 (File No. 001-36137)).

10.6	—	Sprague Resources LP 2013 Long-Term Incentive Plan, effective as of October 28, 2013 (incorporated by reference to Exhibit 4.4 to Sprague Resources LP’s Registration Statement on Form S-8, filed on October 25, 2013 (File No. 333-191923)).

10.7	—	Form of Phantom Unit Award Agreement (incorporated by reference to Exhibit 10.8 to Sprague Resources LP’s Registration Statement on Form S-1, filed on September 24, 2013 (File No. 333-175826)).

10.8	—	Form of Restricted Unit Award Agreement (incorporated by reference to Exhibit 10.9 to Sprague Resources LP’s Registration Statement on Form S-1, filed on September 24, 2013 (File No. 333-175826)).

10.9	—	Form of Unit Award Letter (incorporated by reference to Exhibit 10.10 to Sprague Resources LP’s Registration Statement on Form S-1, filed on September 24, 2013 (File No. 333-175826)).

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

*	Not deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934 or otherwise subject to the liability of that section.

**	To be filed by amendment, in accordance with Rule 405(a)(2)(ii) of Regulation S-T.

Sprague Resources LP - FORM 10-Q - November 27, 2013

Attached files

Sprague Resources LP Reports