STAR GROUP, L.P. - FORM 10-Q

STAR GROUP, L.P. - FORM 10-Q - August 1, 2014

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Attached files

STAR GROUP, L.P. Reports

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EX-32.2 - EX-32.2 - STAR GROUP, L.P.	d724090dex322.htm
EX-32.1 - EX-32.1 - STAR GROUP, L.P.	d724090dex321.htm
EX-31.1 - EX-31.1 - STAR GROUP, L.P.	d724090dex311.htm
EX-31.2 - EX-31.2 - STAR GROUP, L.P.	d724090dex312.htm
EXCEL - IDEA: XBRL DOCUMENT - STAR GROUP, L.P.	Financial_Report.xls

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2014

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

For the transition period from to

Commission File Number: 001-14129

STAR GAS PARTNERS, L.P.

(Exact name of registrants as specified in its charters)


Delaware		06-1437793
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

2187 Atlantic Street Stamford, Connecticut		06902
(Address of principal executive office)

(203) 328-7310

(Registrant’s telephone number, including area code)

(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate 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 Regulation 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 registrants are large accelerated filers, accelerated filers, non-accelerated filers or smaller reporting companies. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Act). Yes ¨ No x

At July 31, 2014, the registrant had 57,467,744 Common Units outstanding.

STAR GAS PARTNERS, L.P. AND SUBSIDIARIES

INDEX TO FORM 10-Q


	Page
Part I Financial Information
Item 1 - Condensed Consolidated Financial Statements
Condensed Consolidated Balance Sheets as of June 30, 2014 (unaudited) and September 30, 2013		3
Condensed Consolidated Statements of Operations (unaudited) for the three and nine months ended June 30, 2014 and June 30, 2013		4
Condensed Consolidated Statements of Comprehensive Income (unaudited) for the three and nine months ended June 30, 2014 and June 30, 2013		5
Condensed Consolidated Statement of Partners’ Capital (unaudited) for the nine months ended June 30, 2014		6
Condensed Consolidated Statements of Cash Flows (unaudited) for the nine months ended June 30, 2014 and June 30, 2013		7
Notes to Condensed Consolidated Financial Statements (unaudited)		8-19
Item 2 - Management’s Discussion and Analysis of Financial Condition and Results of Operations		20-41
Item 3 - Quantitative and Qualitative Disclosures About Market Risk		41
Item 4 - Controls and Procedures		42-43

Part II Other Information:
Item 1 - Legal Proceedings		44
Item 1A - Risk Factors		44
Item 2 - Unregistered Sales of Equity Securities and Use of Proceeds		44
Item 6 - Exhibits		44
Signatures		45

STAR GAS PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS


(in thousands)	June 30, 2014			September 30, 2013
	(unaudited)
ASSETS
Current assets
Cash and cash equivalents	$	7,115		$	85,057
Receivables, net of allowance of $13,024 and $7,928, respectively		211,076			96,124
Inventories		48,587			68,150
Fair asset value of derivative instruments		1,072			646
Current deferred tax assets, net		10,093			32,447
Prepaid expenses and other current assets		25,435			23,456

Total current assets		303,378			305,880


Property and equipment, net		68,050			51,323
Goodwill		209,102			201,130
Intangibles, net		102,941			66,790
Deferred charges and other assets, net		11,672			7,381

Total assets	$	695,143		$	632,504


LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities
Accounts payable	$	22,313		$	18,681
Revolving credit facility borrowings		39,544			—
Fair liability value of derivative instruments		608			3,999
Accrued expenses and other current liabilities		112,643			87,142
Unearned service contract revenue		45,037			40,608
Customer credit balances		31,126			70,196

Total current liabilities		251,271			220,626


Long-term debt		124,543			124,460
Long-term deferred tax liabilities, net		6,638			19,292
Other long-term liabilities		6,600			8,845

Partners’ capital
Common unitholders		328,041			282,289
General partner		126			3
Accumulated other comprehensive loss, net of taxes		(22,076	)		(23,011	)

Total partners’ capital		306,091			259,281

Total liabilities and partners’ capital	$	695,143		$	632,504

See accompanying notes to condensed consolidated financial statements.

STAR GAS PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS


	Three Months Ended June 30,						Nine Months Ended June 30,
(in thousands, except per unit data - unaudited)	2014			2013			2014			2013

Sales:
Product	$	267,694		$	208,862		$	1,571,034		$	1,396,281
Installations and service		58,817			53,662			168,328			167,907

Total sales		326,511			262,524			1,739,362			1,564,188
Cost and expenses:
Cost of product		215,826			163,515			1,213,967			1,091,918
Cost of installations and service		50,003			44,102			156,478			152,661
(Increase) decrease in the fair value of derivative instruments		(3,308	)		1,910			(4,661	)		6,428
Delivery and branch expenses		66,347			53,798			227,175			205,507
Depreciation and amortization expenses		5,760			4,328			15,036			13,007
General and administrative expenses		5,140			4,557			16,995			13,809
Finance charge income		(2,460	)		(1,685	)		(5,671	)		(4,947	)

Operating income (loss)		(10,797	)		(8,001	)		120,043			85,805
Interest expense, net		(5,427	)		(3,536	)		(13,324	)		(10,967	)
Amortization of debt issuance costs		(394	)		(415	)		(1,205	)		(1,325	)

Income (loss) before income taxes		(16,618	)		(11,952	)		105,514			73,513
Income tax expense (benefit)		(7,026	)		(4,364	)		43,602			29,670

Net income (loss)	$	(9,592	)	$	(7,588	)	$	61,912		$	43,843
General Partner’s interest in net income (loss)		(54	)		(41	)		349			237

Limited Partners’ interest in net income (loss)	$	(9,538	)	$	(7,547	)	$	61,563		$	43,606



Basic and diluted income (loss) per Limited Partner Unit (1):	$	(0.17	)	$	(0.13	)	$	0.91		$	0.63


Weighted average number of Limited Partner units outstanding:
Basic and Diluted		57,468			59,370			57,482			59,918

(1)	See Note 14 Earnings (Loss) Per Limited Partner Unit.

See accompanying notes to condensed consolidated financial statements.

STAR GAS PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME


	Three Months Ended June 30,						Nine Months Ended June 30,
(in thousands - unaudited)	2014			2013			2014			2013

Net income (loss)	$	(9,592	)	$	(7,588	)	$	61,912		$	43,843

Other comprehensive income:
Unrealized gain on pension plan obligation (1)		528			664			1,584			1,992
Tax effect of unrealized gain on pension plan		(217	)		(270	)		(649	)		(812	)

Total other comprehensive income		311			394			935			1,180


Total comprehensive income (loss)	$	(9,281	)	$	(7,194	)	$	62,847		$	45,023

(1)	These items are included in the computation of net periodic pension cost. See Note 10 - Employee Benefit Plan.

See accompanying notes to condensed consolidated financial statements.

STAR GAS PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL


	Number of Units
(in thousands - unaudited)	Common			General Partner		Common			General Partner			Accum. Other Comprehensive Income (Loss)			Total Partners’ Capital
Balance as of September 30, 2013		57,718			326	$	282,289		$	3		$	(23,011	)	$	259,281

Net income		—			—		61,563			349			—			61,912
Unrealized gain on pension plan obligation (1)		—			—		—			—			1,584			1,584
Tax effect of unrealized gain on pension plan		—			—		—			—			(649	)		(649	)
Distributions		—			—		(14,511	)		(226	)		—			(14,737	)
Retirement of units (2)		(250	)		—		(1,300	)		—			—			(1,300	)

Balance as of June 30, 2014 (unaudited)		57,468			326	$	328,041		$	126		$	(22,076	)	$	306,091

(1)	These items are included in the computation of net periodic pension cost. See Note 10 - Employee Benefit Plan.

(2)	See Note 3 - Common Unit Repurchase and Retirement.

See accompanying notes to condensed consolidated financial statements.

STAR GAS PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS


	Nine Months Ended June 30,
(in thousands - unaudited)	2014			2013

Cash flows provided by (used in) operating activities:
Net income	$	61,912		$	43,843

Adjustment to reconcile net income to net cash provided by (used in) operating activities:
(Increase) decrease in fair value of derivative instruments		(4,661	)		6,428
Depreciation and amortization		16,241			14,332
Provision for losses on accounts receivable		8,862			7,814
Change in deferred taxes		9,051			4,292
Changes in operating assets and liabilities:
Increase in receivables		(78,276	)		(71,929	)
(Increase) decrease in inventories		24,706			(1,585	)
Decrease in other assets		3,955			6,452
Decrease in accounts payable		(7,132	)		(7,461	)
Decrease in customer credit balances		(43,588	)		(52,719	)
Decrease in other current and long-term liabilities		14,183			18,903

Net cash provided by (used in) operating activities		5,253			(31,630	)


Cash flows provided by (used in) investing activities:
Capital expenditures		(6,510	)		(3,133	)
Proceeds from sales of fixed assets		139			133
Acquisitions (net of cash acquired of $4,151 and $0, respectively)		(97,950	)		(644	)

Net cash used in investing activities		(104,321	)		(3,644	)


Cash flows provided by (used in) financing activities:
Revolving credit facility borrowings		195,482			111,542
Revolving credit facility repayments		(155,938	)		(111,542	)
Distributions		(14,737	)		(14,460	)
Unit repurchases		(1,300	)		(13,940	)
Deferred charges		(2,381	)		(35	)

Net cash provided by (used in) financing activities		21,126			(28,435	)


Net decrease in cash and cash equivalents		(77,942	)		(63,709	)

Cash and cash equivalents at beginning of period		85,057			108,091

Cash and cash equivalents at end of period	$	7,115		$	44,382

See accompanying notes to condensed consolidated financial statements.

STAR GAS PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

1) Partnership Organization

Star Gas Partners, L.P. (“Star Gas Partners,” the “Partnership,” “we,” “us,” or “our”) is a full service provider specializing in the sale of home heating products and services to residential and commercial customers to heat their homes and buildings. The Partnership also services and sells heating and air conditioning equipment to its home heating oil and propane customers and to a lesser extent, provides these offerings to customers outside of our home heating oil and propane customer base. In certain of our marketing areas, we provide home security and plumbing services primarily to our home heating oil and propane customer base. We also sell diesel fuel, gasoline and home heating oil on a delivery only basis. All of these product and services are offered through our home heating oil and propane locations. The Partnership has one reportable segment for accounting purposes. We are the nation’s largest retail distributor of home heating oil, based upon sales volume, operating throughout the Northeast and Mid-Atlantic.

The Partnership is organized as follows:

•

The Partnership is a master limited partnership, which at June 30, 2014, had outstanding 57.5 million Common Units (NYSE: “SGU”) representing 99.44% limited partner interest in Star Gas Partners, and 0.3 million general partner units, representing 0.56% general partner interest in Star Gas Partners. The general partner of the Partnership is Kestrel Heat, LLC, a Delaware limited liability company (“Kestrel Heat” or the “general partner”). The Board of Directors of Kestrel Heat (the “Board”) is appointed by its sole member, Kestrel Energy Partners, LLC, a Delaware limited liability company (“Kestrel”).

•

The Partnership owns 100% of Star Acquisitions, Inc. (“SA”), a Minnesota corporation that owns 100% of Petro Holdings, Inc. (“Petro”). SA and its subsidiaries are subject to Federal and state corporation income taxes. The Partnership’s operations are conducted through Petro and its subsidiaries. Petro is a Northeast and Mid-Atlantic region retail distributor of home heating oil and propane that at June 30, 2014, served approximately 444,000 full-service residential and commercial home heating oil and propane customers. Petro also sold diesel fuel, gasoline and home heating oil to approximately 66,000 customers on a delivery only basis. In addition, Petro installed, maintained, and repaired heating and air conditioning equipment for its customers, and provided ancillary home services, including home security and plumbing, to approximately 22,000 customers.

•

Star Gas Finance Company (“SGFC”) is a 100% owned subsidiary of the Partnership. SGFC serves as the co-issuer, jointly and severally with the Partnership, of its $125 million 8.875% Senior Notes outstanding at June 30, 2014, due 2017. SGFC and the Partnership are dependent on distributions, including inter-company interest payments from its subsidiaries, to service the debt issued by SGFC and the Partnership. The distributions from these subsidiaries are not guaranteed and are subject to certain loan restrictions. SGFC has nominal assets and conducts no business operations. (See Note 9—Long-Term Debt and Bank Facility Borrowings)

2) Summary of Significant Accounting Policies

Basis of Presentation

The Consolidated Financial Statements include the accounts of Star Gas Partners, L.P. and its subsidiaries. All material inter-company items and transactions have been eliminated in consolidation.

The financial information included herein is unaudited; however, such information reflects all adjustments (consisting solely of normal recurring adjustments), which are, in the opinion of management, necessary for the fair statement of financial condition and results for the interim periods. Due to the seasonal nature of the Partnership’s business, the results of operations and cash flows for the nine month period ended June 30, 2014, and June 30, 2013, are not necessarily indicative of the results to be expected for the full year.

These interim financial statements of the Partnership have been prepared in accordance with U.S. Generally Accepted Accounting Principles (“GAAP”) for interim financial information and Rule 10-01 of Regulation S-X of the U.S. Securities and Exchange Commission and should be read in conjunction with the financial statements included in the Partnership’s Annual Report on Form 10-K for the year ended September 30, 2013.

Correction of Immaterial Errors

During the third quarter of fiscal year 2014, we recorded adjustments that reduce net income by $2.2 million ($3.7 million, excluding the related income tax benefit) to correct certain errors related to periods from 2002 through March 31, 2014. The errors include understatements of expenses for state sales and petroleum taxes (“other taxes”) and the related interest and penalties, and overstatements of installations and service sales. The errors were the result of certain control deficiencies that we identified during the quarter. See Item 4. of this Report for additional information concerning these deficiencies.

The impact of the error correction on our condensed consolidated statements of operations for the three months ended June 30, 2014 was an increase in delivery and branch expenses of $1.7 million, an increase to interest expense, net, of $1.4 million, and a reduction of installations and service sales of $0.6 million, offset by the related income tax benefit of $1.5 million. The impact of the error correction on our condensed consolidated statements of operations for the nine months ended June 30, 2014 was an increase in delivery and branch expenses of $1.7 million, an increase to interest expense, net, of $1.2 million, and a reduction of installations and service sales of $0.3 million, offset by the related income tax benefit of $1.3 million. The impact of the error correction on our June 30, 2014, condensed consolidated balance sheet was a decrease to current assets ($2.6 million) for other taxes, interest and penalties already paid and assets written off, and an increase to accrued expenses and other current liabilities ($1.1 million) for the amounts remaining to be paid.

Had these items been recorded timely, the impact would have been a reduction of $0.4 million, $0.3 million and $0.4 million to our reported net income of $29.9 million, $26.0 million and $24.3 million for the years ended September 30, 2013, 2012 and 2011, respectively. Further, net income of $52.2 million and $19.3 million for the three months ended March 31, 2014 and December 31, 2013 would have decreased by $0.1 million and $0.1 million, respectively. In addition, our total partners’ capital of $279.9 million as reported as of September 30, 2010 would have decreased by $1.0 million for errors impacting fiscal years 2002 through 2010.

These errors did not, individually or in the aggregate, result in a material misstatement of our previously issued consolidated financial statements for any period through March 31, 2014. The correction of these errors in the third quarter of fiscal year 2014 was significant to our results of operations for the three months ended June 30, 2014, but had no material effect on our results for the nine months ended June 30, 2014 and is not expected to have a material effect on our results for the full year ending September 30, 2014.

Reclassification

The accompanying June 30, 2013, consolidated statements of operations have been revised from their previous presentation to reclassify finance charge income for the three and nine months period of $1.7 million and $4.9 million respectively, and present it separately as an element of operating income. Previously, finance charge income was included in the caption interest income in the consolidated statements of operations. This reclassification was made in order to conform with common industry practice regarding the reporting of finance charge income in operating income, and had no impact on net income, financial position, and cash flows for any period. Interest expense, net consists of:


(in thousands)	Three Months Ended June 30,						Nine Months Ended June 30,
	2014			2013			2014			2013
Interest expense	$	(5,444	)	$	(3,547	)	$	(13,366	)	$	(10,998	)
Interest income		17			11			42			31

Interest expense, net	$	(5,427	)	$	(3,536	)	$	(13,324	)	$	(10,967	)

Comprehensive Income (Loss)

Comprehensive income (loss) is comprised of net income (loss) and other comprehensive income (loss). Other comprehensive income (loss) consists of the unrealized gain (loss) amortization on the Partnership’s pension plan obligation for its two frozen defined benefit pension plans and the corresponding tax effect.

Recent Accounting Pronouncements

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers. The core principal of this standard is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This new guidance is effective for our annual reporting period beginning in the first quarter of fiscal 2018, with early adoption prohibited. The Partnership is currently evaluating the impact of adopting ASU No. 2014-09.

3) Common Unit Repurchase and Retirement

In July 2012, the Star Board of Directors (“the Board”) authorized the repurchase of up to 3.0 million of the Partnership’s Common Units (“Plan III”). In July 2013, the Board authorized the repurchase of an additional 1.9 million Common Units under Plan III. The authorized Common Unit repurchases may be made from time-to-time in the open market, in privately negotiated transactions or in such other manner deemed appropriate by management. There is no guarantee of the exact number of units that will be purchased under the program and the Partnership may discontinue purchases at any time. The program does not have a time limit. The Board may also approve additional purchases of units from time to time in private transactions. The Partnership’s repurchase activities take into account SEC safe harbor rules and guidance for issuer repurchases. All of the Common Units purchased in the repurchase program will be retired.

Under the Partnership’s second amended and restated credit agreement dated January 14, 2014, in order to repurchase Common Units we must maintain Availability (as defined in the second amended and restated credit facility agreement) of $45 million, 15.0% of the facility size of $300 million (assuming the non-seasonal aggregate commitment is outstanding) on a historical pro forma and forward-looking basis, and a fixed charge coverage ratio of not less than 1.15 measured as of the date of repurchase. The Partnership was in compliance with this covenant (or the equivalent covenant under the credit agreement then in effect) for all unit repurchases made during the nine months ended June 30, 2014.

The following table shows repurchases under Plan III.


(in thousands, except per unit amounts)
Period	Total Number of Units Purchased (a)		Average Price Paid per Unit (b)		Maximum Number of Units that May Yet Be Purchased
Plan III - Number of units authorized						4,894
Private transaction - Number of units authorized (c)						1,150

						6,044


Plan III - Fiscal year 2012 total		22	$	4.26		6,022



Plan III - Fiscal year 2013 total (c)		3,284	$	4.63		2,738



Plan III - First quarter fiscal year 2014 total (d)		250	$	5.20		2,488



Plan III - Second quarter fiscal year 2014 total		—	$	—		2,488



Plan III - Third quarter fiscal year 2014 total		—	$	—		2,488



Plan III - Nine months fiscal year 2014 total		250	$	5.20

(a)	Units were repurchased as part of a publicly announced program, except as noted in a private transaction.

(b)	Amounts include repurchase costs.

(c)	Fiscal year 2013 common unit repurchases include 1.15 million common units acquired in a private transaction.

(d)	First quarter fiscal year 2014 common unit repurchases were acquired in a private transaction.

4) Derivatives and Hedging—Fair Value Measurements and Accounting for the Offsetting of Certain Contracts

The Partnership uses derivative instruments such as futures, options and swap agreements in order to mitigate exposure to market risk associated with the purchase of home heating oil for price-protected customers, physical inventory on hand, inventory in transit, priced purchase commitments and internal fuel usage. The Partnership has elected not to designate its derivative instruments as hedging derivatives, but rather as economic hedges whose change in fair value is recognized in its statement of operations in the line item (Increase) decrease in the fair value of derivative instruments. Depending on the risk being economically hedged, realized gains and losses are recorded in cost of product, cost of installations and service, or delivery and branch expenses.

To hedge a substantial majority of the purchase price associated with heating oil gallons anticipated to be sold to its price-protected customers as of June 30, 2014, the Partnership held 0.1 million gallons of physical inventory and had bought 6.3 million gallons of swap contracts, 1.6 million gallons of call options, 4.0 million gallons of put options and 48.7 million net gallons of synthetic calls, all in future months to match anticipated sales. To hedge the inter-month differentials for its price-protected customers, its physical inventory on hand and inventory in transit, the Partnership, as of June 30, 2014, had bought 52.2 million gallons of future contracts, and had sold 60.2 million gallons of future contracts. In addition to the previously described hedging instruments, the Partnership as of June 30, 2014, had bought corresponding long and short 20.7 million net gallons of swap contracts to lock-in the differential between high sulfur home heating oil and ultra low sulfur diesel. To hedge a majority of its internal fuel usage for the remainder of fiscal 2014, the Partnership as of June 30, 2014, had bought 1.8 million gallons of future swap contracts.

To hedge a substantial majority of the purchase price associated with heating oil gallons anticipated to be sold to its price-protected customers as of June 30, 2013, the Partnership held 1.0 million gallons of physical inventory and had bought 4.3 million gallons of swap contracts, 1.3 million gallons of call options, 3.1 million gallons of put options and 47.1 million net gallons of synthetic calls, all in future months to match anticipated sales. To hedge the inter-month differentials for its price-protected customers, its physical inventory on hand and inventory in transit, the Partnership, as of June 30, 2013, had bought 27.3 million gallons of future contracts, had sold 34.0 million gallons of future contracts and had sold 4.4 million gallons of future swap contracts. To hedge a majority of its internal fuel usage for the remainder of fiscal 2013 the Partnership as of June 30, 2013, had bought 2.0 million gallons of future swap contracts.

The Partnership’s derivative instruments are with the following counterparties: Bank of America, N.A., Bank of Montreal, Cargill, Inc., Citibank, N.A., JPMorgan Chase Bank, N.A., Key Bank, N.A., Regions Financial Corporation, Societe Generale, and Wells Fargo Bank, N.A. The Partnership assesses counterparty credit risk and considers it to be low. We maintain master netting arrangements that allow for the non-conditional offsetting of amounts receivable and payable with counterparties to help manage our risks and record derivative positions on a net basis. The Partnership generally does not receive cash collateral from its counterparties and does not restrict the use of cash collateral it maintains at counterparties. At June 30, 2014, the aggregate cash posted as collateral in the normal course of business at counterparties was $0.8 million. Positions with counterparties who are also parties to our revolving credit facility are collateralized under that facility. As of June 30, 2014, $0.4 million of hedge positions and payable amounts were secured under the credit facility.

FASB ASC 820-10 Fair Value Measurements and Disclosures, established a three-tier fair value hierarchy, which classified the inputs used in measuring fair value. These tiers include: Level 1, defined as observable inputs such as quoted prices for identical instruments in active markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions. The Partnership’s Level 1 derivative assets and liabilities represent the fair value of commodity contracts used in its hedging activities that are identical and traded in active markets. The Partnership’s Level 2 derivative assets and liabilities represent the fair value of commodity contracts used in its hedging activities that are valued using either directly or indirectly observable inputs, whose nature, risk and class are similar. No significant transfers of assets or liabilities have been made into and out of the Level 1 or Level 2 tiers. All derivative instruments were non-trading positions and were either a Level 1 or Level 2 instrument. The fair market value of our Level 1 and Level 2 derivative assets and liabilities are calculated by our counter-parties and are independently validated by the Partnership. The Partnership’s calculations are, for Level 1 derivative assets and liabilities, based on the published New York Mercantile Exchange (“NYMEX”) market prices for the commodity contracts open at the end of the period. For Level 2 derivative assets and liabilities the calculations performed by the Partnership are based on a combination of the NYMEX published market prices and other inputs, including such factors as present value, volatility and duration.

The Partnership had no assets or liabilities that are measured at fair value on a nonrecurring basis subsequent to their initial recognition. The Partnership’s financial assets and liabilities measured at fair value on a recurring basis are listed on the following table.


(In thousands)					Fair Value Measurements at Reporting Date Using:
Derivatives Not Designated as Hedging Instruments Under FASB ASC 815-10	Balance Sheet Location	Total			Quoted Prices in Active Markets for Identical Assets Level 1			Significant Other Observable Inputs Level 2			Significant Unobservable Inputs Level 3
Asset Derivatives at June 30, 2014
Commodity contracts	Fair asset and fair liability value of derivative instruments	$	10,035		$	3,855		$	6,180		$	—

Commodity contract assets at June 30, 2014		$	10,035		$	3,855		$	6,180		$	—


Liability Derivatives at June 30, 2014
Commodity contracts	Fair liability and fair asset value of derivative instruments	$	(9,571	)	$	(4,348	)	$	(5,223	)	$	—

Commodity contract liabilities at June 30, 2014		$	(9,571	)	$	(4,348	)	$	(5,223	)	$	—


Asset Derivatives at September 30, 2013
Commodity contracts	Fair asset and fair liability value of derivative instruments	$	14,467		$	1,175		$	13,292		$	—

Commodity contract assets at September 30, 2013		$	14,467		$	1,175		$	13,292		$	—


Liability Derivatives at September 30, 2013
Commodity contracts	Fair liability and fair asset value of derivative instruments	$	(17,820	)	$	(519	)	$	(17,301	)	$	—

Commodity contract liabilities at September 30, 2013		$	(17,820	)	$	(519	)	$	(17,301	)	$	—

The Partnership’s derivative assets (liabilities) offset by counterparty and subject to an enforceable master netting arrangement are listed on the following table.


(In thousands)									Gross Amounts Not Offset in the Statement of Financial Position
Offsetting of Financial Assets (Liabilities) and Derivative Assets (Liabilities)	Gross Assets Recognized		Gross Liabilities Offset in the Statement of Financial Position			Net Assets (Liabilities) Presented in the Statement of Financial Position			Financial Instruments		Cash Collateral Received		Net Amount
Fair asset value of derivative instruments	$	1,928	$	(856	)	$	1,072		$	—	$	—	$	1,072
Fair liability value of derivative instruments		8,107		(8,715	)		(608	)		—		—		(608	)

Total at June 30, 2014	$	10,035	$	(9,571	)	$	464		$	—	$	—	$	464


Fair asset value of derivative instruments	$	7,254	$	(6,608	)	$	646		$	—	$	—	$	646
Fair liability value of derivative instruments		7,213		(11,212	)		(3,999	)		—		—		(3,999	)

Total at September 30, 2013	$	14,467	$	(17,820	)	$	(3,353	)	$	—	$	—	$	(3,353	)


(In thousands)	The Effect of Derivative Instruments on the Statement of Operations

		Amount of (Gain) or Loss Recognized
Derivatives Not Designated as Hedging Instruments Under FASB ASC 815-10	Location of (Gain) or Loss Recognized in Income on Derivative	Three Months Ended June 30, 2014			Three Months Ended June 30, 2013			Nine Months Ended June 30, 2014			Nine Months Ended June 30, 2013
Closed Positions
Commodity contracts	Cost of product (a)	$	2,718		$	2,531		$	11,245		$	15,951
Commodity contracts	Cost of installations and service (a)	$	(82	)	$	(67	)	$	(177	)	$	(401	)
Commodity contracts	Delivery and branch expenses (a)	$	(5	)	$	(43	)	$	(119	)	$	(246	)

(a) Represents realized closed positions and includes the cost of options as they expire.

Open Positions
Commodity contracts	(Increase) / decrease in the fair value of derivative instruments	$	(3,308	)	$	1,910		$	(4,661	)	$	6,428

5) Inventories

The Partnership’s product inventories are stated at the lower of cost or market computed on the weighted average cost method. All other inventories, representing parts and equipment are stated at the lower of cost or market using the FIFO method. The components of inventory were as follows (in thousands):


	June 30, 2014		September 30, 2013
Product	$	28,404	$	50,197
Parts and equipment		20,183		17,953

Total inventory	$	48,587	$	68,150

6) Property and Equipment

Property and equipment are stated at cost. Depreciation is computed over the estimated useful lives of the depreciable assets using the straight-line method (in thousands):


	June 30, 2014		September 30, 2013

Property and equipment	$	192,406	$	170,462
Less: accumulated depreciation		124,356		119,139

Property and equipment, net	$	68,050	$	51,323

7) Business Combination

On March 4, 2014 (the “Acquisition Date”), the Partnership completed the acquisition of Griffith Energy Services, Inc. (“Griffith”) of Columbia, Maryland, from Central Hudson Enterprises Corporation. The Partnership purchased 100% of the stock of Griffith for $98.7 million, consisting of $69.9 million paid for the long term assets and $28.8 million paid for estimated working capital (net of $4.2 million of cash acquired). In addition, the Partnership issued $8.5 million in letters of credit for supply and insurance purposes. There was no long-term debt assumed in the acquisition. The business reason for this acquisition is that Griffith, being a 100-year-old brand that is broadly recognized as a premier fuel and service provider in its territories, is an excellent strategic fit for the Partnership. The Griffith acquisition adds scale to the Partnership and leverages our existing fixed cost base, providing access to approximately 50,000 residential and commercial accounts across the Mid-Atlantic region.

The following table summarizes the preliminary fair values and purchase price allocation at the acquisition date, of the assets acquired and liabilities assumed related to the Griffith acquisition as of the Acquisition Date.


(in thousands)	As of Acquisition Date
Trade accounts receivable (a)	$	46,557
Inventories		5,143
Other current assets		5,459
Property and equipment		17,478
Customer lists, trade names and other intangibles		44,400
Other long term assets		1,778
Current liabilities		(30,089	)

Total net identifiable assets acquired	$	90,726


Total consideration	$	98,698
Less: Total net identifiable assets acquired		90,726

Goodwill	$	7,972

(a)	The gross contractual receivable amount is $48.2 million, and the best estimate at the acquisition date of the contractual cash flows not expected to be collected is $1.7 million.

The total costs of $0.8 million related to this acquisition are included in the Consolidated Statement of Operations under general and administrative expenses for the three and nine months ended June 30, 2014.

All of the $8.0 million of goodwill relating to the Griffith acquisition is expected to be deductible for income tax purposes.

Griffith’s operating results are included in the Partnership’s consolidated financial statements starting on the Acquisition Date. Customer lists, other intangibles and trade names are amortized on a straight-line basis over ten to twenty years.

Included in our consolidated statement of operations from the Acquisition Date through June 30, 2014, are Griffith’s sales and net earnings before income taxes of $86.9 million and $0.4 million, respectively.

The following table provides unaudited pro forma results of operations as if the Griffith acquisition had occurred on October 1, 2012, the beginning of fiscal year 2013. The unaudited pro forma results were prepared using Griffith’s current and prior year financial information, reflecting certain adjustments related to the acquisition, such as the elimination of directly attributable acquisition expenses and changes to depreciation and amortization expenses. These pro forma adjustments do not include any potential synergies related to combining the businesses. Accordingly, such pro forma operating results were prepared for comparative purposes only and do not purport to be indicative of what would have occurred had the acquisition been made as of October 1, 2012 or of results that may occur in the future.


	Three Months Ended						Nine Months Ended
	June 30,						June 30,
(in thousands)	2014			2013			2014		2013

Total sales	$	326,511		$	319,784		$	1,910,068	$	1,808,630

Net income (loss)	$	(9,592	)	$	(9,445	)	$	66,731	$	47,546

8) Goodwill and Intangibles, net

Goodwill

A summary of changes in the Partnership’s goodwill is as follows (in thousands):


Balance as of September 30, 2013	$	201,130
Fiscal year 2014 business combination		7,972

Balance as of June 30, 2014	$	209,102

Intangibles, net

The gross carrying amount and accumulated amortization of intangible assets subject to amortization are as follows (in thousands):


	June 30, 2014						September 30, 2013
	Gross						Gross
	Carrying		Accumulated				Carrying		Accumulated
	Amount		Amortization		Net		Amount		Amortization		Net
Customer lists and other intangibles	$	332,411	$	229,470	$	102,941	$	288,011	$	221,221	$	66,790

Amortization expense for intangible assets was $8.2 million for the nine months ended June 30, 2014, compared to $6.8 million for the nine months ended June 30, 2013. Total estimated annual amortization expense related to intangible assets subject to amortization, for the fiscal year ending September 30, 2014, and the four succeeding fiscal years ending September 30, is as follows (in thousands):


	Estimated Annual Book Amortization Expense
2014	$	11,540
2015	$	13,085
2016	$	12,914
2017	$	12,394
2018	$	11,555

9) Long-Term Debt and Bank Facility Borrowings

The Partnership’s debt is as follows (in thousands):


	June 30, 2014				September 30, 2013
	Carrying				Carrying
	Amount		Fair Value (a)		Amount		Fair Value (a)
8.875% Senior Notes (b)	$	124,543	$	131,563	$	124,460	$	130,000
Revolving Credit Facility Borrowings (c)		39,544		39,544		—		—

Total debt	$	164,087	$	171,107	$	124,460	$	130,000

Total long-term portion of debt	$	124,543	$	131,563	$	124,460	$	130,000

(a)	The Partnership’s fair value estimates of long-term debt are made at a specific point in time, based on Level 2 inputs. Due to the relatively short maturity of the revolving credit facility, the carrying amount approximates fair value.

(b)

The 8.875% Senior Notes were originally issued in November 2010 in a private placement offering pursuant to Rule 144A and Regulation S under the Securities Act of 1933, and in February 2011, were exchanged for substantially identical public notes registered with the Securities and Exchange Commission. These public notes mature in December 2017 and accrue interest at an annual rate of 8.875% requiring semi-annual interest payments on June 1 and December 1 of each year. The discount on these notes was $0.5 million at June 30, 2014. Under the terms of the indenture, these notes permit restricted payments after passing particular financial tests. The Partnership can incur debt up to $100 million for acquisitions and can also pay restricted payments of $22.0 million without passing certain financial tests.

(c)	In January 2014, the Partnership entered into a second amended and restated asset based revolving credit facility agreement with a bank syndicate comprised of fifteen participants, which replaced the existing revolving credit facility.

The second amended and restated revolving credit facility provides the Partnership with the ability to borrow up to $300 million ($450 million during the heating season of December through April of each year) for working capital purposes (subject to certain borrowing base limitations and coverage ratios), including the issuance of up to $100 million in letters of credit, and extends the maturity date to June 2017, or January 2019 if the Partnership has met the conditions of the facility termination date as defined in the agreement and as discussed further below. The Partnership can increase the facility size by $100 million without the consent of the bank group. However, the bank group is not obligated to fund the $100 million increase. If the bank group elects not to fund the increase, the Partnership can add additional lenders to the group, with the consent of the Agent, which shall not be unreasonably withheld. Obligations under the second amended and restated credit facility are guaranteed by the Partnership and its subsidiaries and are secured by liens on substantially all of the Partnership’s assets including accounts receivable, inventory, general intangibles, real property, fixtures and equipment.

The interest rate on the second amended and restated credit facility is LIBOR plus (i) 1.75% (if Availability, as defined in the agreement is greater than or equal to $150 million), or (ii) 2.00% (if Availability is greater than $75 million but less than $150 million), or (iii) 2.25% (if Availability is less than or equal to $75 million). The Commitment Fee on the unused portion of the facility is 0.30% per annum.

Under the second amended and restated credit facility, the Partnership is obligated to meet certain financial covenants, including the requirement to maintain at all times either Availability (borrowing base less amounts borrowed and letters of credit issued) of 12.5% of the facility size, or a fixed charge coverage ratio (as defined in the revolving credit facility agreement) of not less than 1.1, which is calculated based upon Adjusted EBITDA for the trailing twelve months. In order to make acquisitions, the Partnership must maintain Availability of $40 million on a historical pro forma and forward-looking basis. In addition, the Partnership must maintain Availability of $45 million, 15.0% of the facility size of $300 million (assuming the non-seasonal aggregate commitment is outstanding), on a historical and forward-looking basis, and a fixed charge coverage ratio of not less than 1.15 in order to pay any distributions to unitholders or repurchase Common Units. No inter-company dividends or distributions can be made (including those needed to pay interest or principle on our 8.875% Senior Notes), except to the Partnership or a wholly owned subsidiary of the Partnership, if the immediately preceding covenants have not been met. Certain restrictions are also imposed by the agreement, including restrictions on the Partnership’s ability to incur additional indebtedness, to pay distributions to unitholders, to pay inter-company dividends or distributions, make investments, grant liens, sell assets, make acquisitions and engage in certain other activities.

All outstanding amounts owed under the second amended and restated credit facility become due and payable on the facility termination date of June 1, 2017. If the Partnership has repaid, prepaid or otherwise defeased at least $100 million of our 8.875% Senior Notes and Availability is equal to or greater than the aggregate amount required to repay the remaining outstanding 8.875% Senior Notes (“Payoff Amount”), then the facility termination date is January 14, 2019. However, after June 1, 2017, in the event that Availability is less than the Payoff Amount, the facility termination date shall be three days following such date. Notwithstanding this, all outstanding amounts are subject to acceleration upon the occurrence of events of default which the Partnership considers usual and customary for an agreement of this type, including failure to make payments under the second amended and restated credit facility, non-performance of covenants and obligations or insolvency or bankruptcy (as described in the second amended and restated credit facility).

At June 30, 2014, $39.5 million was outstanding under the revolving credit facility and $52.5 million of letters of credit were issued. At September 30, 2013, no amount was outstanding under the revolving credit facility and $44.7 million of letters of credit were issued.

At June 30, 2014, availability was $120.9 million and the Partnership was in compliance with the fixed charge coverage ratio. At September 30, 2013, availability was $164.3 million and the Partnership was in compliance with the fixed charge coverage ratio.

In July 2011, the Partnership’s shelf registration became effective, providing for the sale of up to $250 million in one or more offerings of Common Units representing limited partnership interests, partnership securities and debt securities; which may be secured or unsecured senior debt securities or secured or unsecured subordinated debt securities. This shelf registration expired in July 2014 and no offerings under this shelf registration occurred.

10) Employee Benefit Plan


	Three Months Ended						Nine Months Ended
	June 30,						June 30,
(in thousands)	2014			2013			2014			2013

Components of net periodic benefit cost:
Service cost	$	0		$	0		$	0		$	0
Interest cost		690			620			2,070			1,860
Expected return on plan assets		(776	)		(948	)		(2,328	)		(2,844	)
Net amortization		528			664			1,584			1,992

Net periodic benefit cost	$	442		$	336		$	1,326		$	1,008

For the nine months ended June 30, 2014, the Partnership contributed $1.4 million and expects to make an additional $0.6 million contribution in fiscal 2014 to fund its pension obligation.

11) Income Taxes

Since Star Gas Partners is organized as a master limited partnership, it is not subject to tax at its entity level for Federal and state income tax purposes. However, Star Gas Partners’ income is derived from its corporate subsidiaries, and these entities do incur Federal and state income taxes relating to their respective corporate subsidiaries, which are reflected in these financial statements. For the corporate subsidiaries of Star Gas Partners, a consolidated Federal income tax return is filed.

Income and losses of Star Gas Partners are allocated directly to the individual partners. Even though Star Gas Partners will generate non-qualifying Master Limited Partnership income through its corporate subsidiaries, cash received by Star Gas Partners from its corporate subsidiaries is generally included in the determination of qualified Master Limited Partnership income. All or a portion of such cash could be taxable as dividend income or as a capital gain to the individual partners. This could be the case even if Star Gas Partners used the cash received from its corporate subsidiaries for purposes such as the repurchase of common units rather than distributions to its individual partners.

The accompanying financial statements are reported on a fiscal year, however, Star Gas Partners and its Corporate subsidiaries file Federal and state income tax returns on a calendar year.

The current and deferred income tax expenses for the three and nine months ended June 30, 2014, and 2013 are as follows:


	Three Months Ended						Nine Months Ended
	June 30,						June 30,
(in thousands)	2014			2013			2014		2013

Income (loss) before income taxes	$	(16,618	)	$	(11,952	)	$	105,514	$	73,513

Current tax expense (benefit)	$	(7,888	)	$	(5	)	$	34,550	$	25,378
Deferred tax expense (benefit)		862			(4,359	)		9,052		4,292

Total tax expense (benefit)	$	(7,026	)	$	(4,364	)	$	43,602	$	29,670

As of January 1, 2014, Star Acquisitions, Inc., a wholly-owned subsidiary of the Partnership, had an estimated Federal net operating loss carry forward (“NOLs”) of approximately $8.3 million. The Federal NOLs, which will expire between 2018 and 2024, are generally available to offset any future taxable income but are also subject to annual limitations of between $1.0 million and $2.2 million.

FASB ASC 740-10-05-6 Income Taxes, Uncertain Tax Position, provides financial statement accounting guidance for uncertainty in income taxes and tax positions taken or expected to be taken in a tax return. At June 30, 2014, we had unrecognized income tax benefits totaling $0.9 million including related accrued interest and penalties of $0.2 million. These unrecognized tax benefits are primarily the result of state tax uncertainties. If recognized, these tax benefits would be recorded as a benefit to the effective tax rate.

We believe that the total liability for unrecognized tax benefits will not materially change during the next 12 months ending June 30, 2015. Our continuing practice is to recognize interest related to income tax matters as a component of income tax expense. We file U.S. Federal income tax returns and various state and local returns. A number of years may elapse before an uncertain tax position is audited and finally resolved. For our Federal income tax returns we have four tax years subject to examination. In our major state tax jurisdictions of New York, Connecticut, Pennsylvania and New Jersey, we have four, four, four and five tax years, respectively, that are subject to examination. While it is often difficult to predict the final outcome or the timing of resolution of any particular uncertain tax position, based on our assessment of many factors including past experience and interpretation of tax law, we believe that our provision for income taxes reflect the most probable outcome. This assessment relies on estimates and assumptions and may involve a series of complex judgments about future events.

12) Supplemental Disclosure of Cash Flow Information


	Nine Months Ended
	June 30,
(in thousands)	2014		2013

Cash paid during the period for:
Income taxes, net	$	26,073	$	11,864
Interest	$	16,023	$	13,771
Non-cash financing activities:
Increase in interest expense - amortization of debt discount on 8.875% Senior Note	$	83	$	77

13) Commitments and Contingencies

The Partnership’s operations are subject to the operating hazards and risks normally incidental to handling, storing and transporting and otherwise providing for use by consumers of hazardous liquids such as home heating oil and propane. As a result, at any given time, the Partnership is generally a defendant in various legal proceedings and litigation arising in the ordinary course of business. The Partnership maintains insurance policies in amounts and with coverages and deductibles we believe are reasonable and prudent. However, the Partnership cannot assure that this insurance will be adequate to protect it from all material expenses related to potential future claims for personal and property damage or that these levels of insurance will be available in the future at economical prices. The Partnership does not carry business interruption insurance. In the opinion of management the Partnership is not a party to any litigation which, individually or in the aggregate, could reasonably be expected to have a material adverse effect on the Partnership’s results of operations, financial position or liquidity.

14) Earnings (Loss) Per Limited Partner Unit

Income per limited partner unit is computed in accordance with FASB ASC 260-10-05 Earnings Per Share, Master Limited Partnerships (EITF 03-06), by dividing the limited partners’ interest in net income by the weighted average number of limited partner units outstanding. The pro forma nature of the allocation required by this standard provides that in any accounting period where the Partnership’s aggregate net income exceeds its aggregate distribution for such period, the Partnership is required to present net income per limited partner unit as if all of the earnings for the periods were distributed, regardless of whether those earnings would actually be distributed during a particular period from an economic or practical perspective. This allocation does not impact the Partnership’s overall net income or other financial results. However, for periods in which the Partnership’s aggregate net income exceeds its aggregate distributions for such period, it will have the impact of reducing the earnings per limited partner unit, as the calculation according to this standard results in a theoretical increased allocation of undistributed earnings to the general partner. In accounting periods where aggregate net income does not exceed aggregate distributions for such period, this standard does not have any impact on the Partnership’s net income per limited partner unit calculation. A separate and independent calculation for each quarter and year-to-date period is performed, in which the Partnership’s contractual participation rights are taken into account.

The following presents the net income allocation and per unit data using this method for the periods presented:


	Three Months Ended						Nine Months Ended
Basic and Diluted Earnings (Loss) Per Limited Partner:	June 30,						June 30,
(in thousands, except per unit data)	2014			2013			2014		2013
Net income (loss)	$	(9,592	)	$	(7,588	)	$	61,912	$	43,843
Less General Partner’s interest in net income (loss)		(54	)		(41	)		349		237

Net income (loss) available to limited partners		(9,538	)		(7,547	)		61,563		43,606

Less dilutive impact of theoretical distribution of earnings under FASB ASC 260-10-45-60		—			—			9,152		5,623

Limited Partner’s interest in net income (loss) under FASB ASC 260-10-45-60	$	(9,538	)	$	(7,547	)	$	52,411	$	37,983


Per unit data:
Basic and diluted net income (loss) available to limited partners	$	(0.17	)	$	(0.13	)	$	1.07	$	0.73

Less dilutive impact of theoretical distribution of earnings under FASB ASC 260-10-45-60		—			—			0.16		0.10

Limited Partner’s interest in net income (loss) under FASB ASC 260-10-45-60	$	(0.17	)	$	(0.13	)	$	0.91	$	0.63


Weighted average number of Limited Partner units outstanding		57,468			59,370			57,482		59,918

15) Subsequent Events

Quarterly Distribution Declared

In July 2014, we declared a quarterly distribution of $0.0875 per unit, or $0.35 per unit on an annualized basis, on all Common Units with respect to the third quarter of fiscal 2014, payable on August 8, 2014, to holders of record on July 31, 2014. In accordance with our Partnership Agreement, the amount of distributions in excess of the minimum quarterly distribution of $0.0675, are distributed 90% to Common Unit holders and 10% to the General Partner unit holders (until certain distribution levels are met), subject to the management incentive compensation plan. As a result, $5.0 million will be paid to the Common Unit holders, $0.1 million to the General Partner unit holders (including $0.06 million of incentive distribution as provided in our Partnership Agreement) and $0.06 million to management pursuant to the management incentive compensation plan which provides for certain members of management to receive incentive distributions that would otherwise be payable to the General Partner.

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Statement Regarding Forward-Looking Disclosure

This Quarterly Report on Form 10-Q includes “forward-looking statements” which represent our expectations or beliefs concerning future events that involve risks and uncertainties, including those associated with the effect of weather conditions on our financial performance, the price and supply of the products that we sell, the consumption patterns of our customers, our ability to obtain satisfactory gross profit margins, our ability to obtain new customers and retain existing customers, our ability to make strategic acquisitions, the impact of litigation, our ability to contract for our current and future supply needs, natural gas conversions, future union relations and the outcome of current and future union negotiations, the impact of current and future governmental regulations, including environmental, health, and safety regulations, the ability to attract and retain employees, customer credit worthiness, counterparty credit worthiness, marketing plans, general economic conditions and new technology. All statements other than statements of historical facts included in this Report including, without limitation, the statements under “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and elsewhere herein, are forward-looking statements. Without limiting the foregoing, the words “believe,” “anticipate,” “plan,” “expect,” “seek,” “estimate,” and similar expressions are intended to identify forward-looking statements. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to be correct and actual results may differ materially from those projected as a result of certain risks and uncertainties. These risks and uncertainties include, but are not limited to, those set forth under the heading “Risk Factors” and “Business Strategy” in our Annual Report on Form 10-K (the “Form 10-K”) for the fiscal year ended September 30, 2013, and under the heading “Risk Factors” in this Quarterly Report on Form 10-Q. Important factors that could cause actual results to differ materially from our expectations (“Cautionary Statements”) are disclosed in the Annual Report on Form 10-K and in this Quarterly Report on Form 10-Q. All subsequent written and oral forward-looking statements attributable to the Partnership or persons acting on its behalf are expressly qualified in their entirety by the Cautionary Statements. Unless otherwise required by law, we undertake no obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise after the date of this Report.

Overview

The following is a discussion of our historical financial condition and results of our operations and should be read in conjunction with the description of our business and the historical financial and operating data and notes thereto included elsewhere in this Report.

Seasonality

The following matters should be considered in analyzing our financial results. Our fiscal year ends on September 30. All references to quarters and years respectively in this document are to the fiscal quarters and years unless otherwise noted. The seasonal nature of our business has resulted, on average during the last five years, in the sale of approximately 30% of our volume of home heating oil and propane in the first fiscal quarter and 50% of our volume in the second fiscal quarter, the peak heating season. We generally realize net income in both of these quarters and net losses during the quarters ending June and September. In addition, sales volume typically fluctuates from year to year in response to variations in weather, wholesale energy prices and other factors.

Degree Day

A “degree day” is an industry measurement of temperature designed to evaluate energy demand and consumption. Degree days are based on how far the average daily temperature departs from 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 (multi-year) average to see if a given month or year was warmer or cooler than usual. Degree days are officially observed by the National Weather Service.

Every ten years, the National Oceanic and Atmospheric Administration (“NOAA”) computes and publishes average meteorological quantities, including average temperatures for the last 30 years by geographical location, and the corresponding degree days. The latest and most widely used data covers the years from 1981 through 2010. Our calculations of normal weather are based on these published 30 year averages for heating degree days, weighted by volume for the locations where we have existing operations.

Home Heating Oil Price Volatility

The wholesale price of home heating oil can be volatile, resulting in increased consumer price sensitivity to heating costs and increased gross customer losses. As a commodity, the price of home heating oil is generally impacted by many factors, including economic and geopolitical forces. The price of home heating oil is closely linked to the price refiners pay for crude oil, which is the principal cost component of home heating oil. The volatility in the wholesale cost of home heating oil, as measured by the New York Mercantile Exchange (“NYMEX”) price per gallon for the fiscal years ending September 30, 2010 through 2014, on a quarterly basis, is illustrated in the following chart:


	Fiscal 2014				Fiscal 2013 ⁽¹⁾				Fiscal 2012				Fiscal 2011				Fiscal 2010
Quarter Ended	Low		High		Low		High		Low		High		Low		High		Low		High
December 31	$	2.84	$	3.12	$	2.90	$	3.26	$	2.72	$	3.17	$	2.19	$	2.54	$	1.78	$	2.12
March 31		2.89		3.28		2.86		3.24		2.99		3.32		2.49		3.09		1.89		2.20
June 30		2.85		3.05		2.74		3.09		2.53		3.25		2.75		3.32		1.87		2.35
September 30		—		—		2.87		3.21		2.68		3.24		2.77		3.13		1.92		2.24

(1)	Beginning April 1, 2013, the NYMEX contract specifications were changed from high sulfur home heating oil to ultra low sulfur diesel.

Impact on Liquidity of Wholesale Product Cost Volatility

Our liquidity is adversely impacted in times of increasing wholesale product costs, as we must use more cash to fund our hedging requirements and a portion of the increased levels of accounts receivable and inventory. Our liquidity is also adversely impacted at times by sudden and sharp decreases in wholesale product costs due to the increased margin requirements for futures contracts and collateral requirements for options and swaps that we use to manage market risks.

Weather Hedge Contract — Fiscal Years 2013, 2014 and 2015

In July 2012, the Partnership entered into a weather hedge contract for fiscal years 2013, 2014 and 2015, with Swiss Re Financial Products Corporation, under which the Partnership is entitled to receive a payment of $35,000 per heating degree-day shortfall if the total number of heating degree-days in the period covered is less than 92.5% of the ten year average (the “Payment Threshold”). The hedge covers the period from November 1 through March 31, taken as a whole, for each respective fiscal year and has a maximum payout of $12.5 million for each fiscal year. The Partnership did not record any benefit under its weather hedge contract during fiscal 2013 and has not recorded any benefit for the nine months ended June 30, 2014.

Per Gallon Gross Profit Margins

We believe home heating oil and propane margins should be evaluated on a cents per gallon basis, before the effects of increases or decreases in the fair value of derivative instruments (as we believe that realized per gallon margins should not include the impact of non-cash changes in the market value of hedges before the settlement of the underlying transaction).

A significant portion of our home heating oil volume is sold to individual customers under an arrangement pre-establishing a ceiling price or fixed price for home heating oil over a fixed period of time, generally twelve months (“price-protected” customers). When these price-protected customers agree to purchase home heating oil from us for the next heating season, we purchase option contracts, swaps and futures contracts for a substantial majority of the heating oil that we expect to sell to these customers. The amount of home heating oil volume that we hedge per price-protected customer is based upon the estimated fuel consumption per average customer per month. In the event that the actual usage exceeds the amount of the hedged volume on a monthly basis, we may be required to obtain additional volume at unfavorable costs. In addition, should actual usage in any month be less than the hedged volume, our hedging cost per gallon could be greater, thus reducing expected margins.

Derivatives

FASB ASC 815-10-05 Derivatives and Hedging requires that derivative instruments be recorded at fair value and included in the consolidated balance sheet as assets or liabilities. To the extent derivative instruments designated as cash flow hedges are effective, as defined under this guidance, changes in fair value are recognized in other comprehensive income until the forecasted hedged item is recognized in earnings. We have elected not to designate our derivative instruments as hedging instruments under this guidance, and as a result, the changes in fair value of the derivative instruments are recognized in our statement of operations. Therefore, we experience volatility in earnings as outstanding derivative instruments are marked to market and non-cash gains and losses are recorded prior to the sale of the commodity to the customer. The volatility in any given period related to unrealized non-cash gains or losses on derivative instruments can be significant to our overall results. However, we ultimately expect those gains and losses to be offset by the cost of product when purchased.

Griffith Acquisition

On March 4, 2014, the Partnership completed the acquisition of Griffith Energy Services, Inc. (“Griffith”) of Columbia, Maryland, from Central Hudson Enterprises Corporation. The Partnership purchased 100% of the stock of Griffith for $98.7 million, consisting of $69.9 million paid for the long term assets and $28.8 million paid for estimated working capital (net of $4.2 million of cash acquired). In addition, the Partnership issued $8.5 million in letters of credit for supply and insurance purposes. There was no long-term debt assumed in the acquisition. The Griffith acquisition added scale to the Partnership and leveraged our existing fixed cost base, providing access to approximately 50,000 residential and commercial accounts across the Mid-Atlantic region. For Griffith’s fiscal year ended December 31, 2013, Griffith sold 78.4 million gallons of petroleum products including 29.0 million gallons of home heating oil, 0.9 million gallons of propane and 48.5 million gallons of motor fuel.

Impact of Sandy

On October 29, 2012, the storm known as “Sandy” made landfall in our service area, resulting in widespread power outages for a number of our customers. In addition, certain third-party terminals where we purchase and store liquid product were closed for a short period of time due to damage sustained from the storm or by the loss of power. During the period subsequent to the storm, our operations and systems functioned without any meaningful disruptions.

Deliveries of home heating oil and propane were less than expected for certain of our customers who were without power for several weeks subsequent to Sandy. However, since our operations were able to provide uninterrupted service to current and new customers, our sales of diesel fuel increased during the weeks after the storm, as did our service and installation sales, along with the related costs to provide these services.

Income Taxes

Net Operating Loss Carry Forwards

The Partnership and its corporate subsidiaries file Federal and state income tax returns on a calendar year basis. As of January 1, 2014, our Federal Net Operating Loss carry forwards (“NOLs”) were estimated to be $8.3 million, subject to annual limitations of between $1.0 million and $2.2 million on the amount of such losses that can be used.

Book Versus Tax Deductions

The amount of cash flow that we generate in any given year depends upon a variety of factors including the amount of cash income taxes that our corporate subsidiaries are required to pay. The amount of depreciation and amortization that we deduct for book (i.e., financial reporting) purposes will differ from the amount that our subsidiaries can deduct for tax purposes. The table below compares the estimated depreciation and amortization for book purposes to the amount that our subsidiaries expect to deduct for tax purposes based on currently owned assets. Our subsidiaries file their tax returns based on a calendar year basis. The amounts below are based on our September 30 fiscal year and are reflective of fixed assets additions and acquisitions through June 30, 2014, including the Griffith acquisition.

Estimated Depreciation and Amortization Expense


(in thousands) Fiscal Year	Book		Tax
2014	$	22,382	$	34,371
2015		23,695		33,492
2016		21,959		26,270
2017		20,216		18,368
2018		17,962		14,822
2019		15,127		11,717

Non-Deductible Partnership Expenses

The Partnership incurs certain expenses at the Partnership level that are not deductible for Federal or state income tax purposes by our corporate subsidiaries. As a result, our effective tax rate could differ from the statutory rate that would be applicable if such expenses were deductible.

Income Taxes—Election to be Taxed as an Association or “C Corporation”

The Partnership is evaluating whether to make certain elections for Federal and State tax purposes to both better rationalize our tax reporting structure and to reduce costs.

The production of the Partnership’s K-1 forms is an expensive, time consuming and administratively intensive process. Due to our existing tax structure, our unit holders typically do not receive the tax benefits normally associated with owning units in a publicly traded master limited partnership, as the source of much of the Partnership’s income is from corporations below the Partnership and is subject to corporate level income taxes. Certain cash transfers from our corporations to the Partnership are generally treated as dividends, and may be taxable to the unit holders regardless as to whether the Partnership actually distributes any cash to them. For example, cash sent by our corporate subsidiary to the Partnership for unit repurchases may be treated as dividend income to all our unit holders.

If such an election is made, we would still remain a publicly traded partnership for legal and governance purposes. For income tax purposes, our unit holders would be treated as owning stock in a corporation rather than being partners in a partnership. By making certain elections, the resulting complexities from cash movements will be reduced and certain administrative costs eliminated.

EBITDA and Adjusted EBITDA (non-GAAP financial measures)

EBITDA (Earnings from continuing operations before net interest expense, income taxes, depreciation and amortization) and Adjusted EBITDA (Earnings from continuing operations before net interest expense, income taxes, depreciation and amortization, (increase) decrease in the fair value of derivatives, gain or loss on debt redemption, goodwill impairment, and other non-cash and non-operating charges) are non-GAAP financial measures that are used as supplemental financial measures by management and external users of our financial statements, such as investors, commercial banks and research analysts, to assess:

•

our compliance with certain financial covenants included in our debt agreements;

•

our financial performance without regard to financing methods, capital structure, income taxes or historical cost basis;

•

our ability to generate cash sufficient to pay interest on our indebtedness and to make distributions to our partners;

•

our operating performance and return on invested capital compared to those of other companies in the retail distribution of refined petroleum products, without regard to financing methods and capital structure; and

•

the viability of acquisitions and capital expenditure projects and the overall rates of return of alternative investment opportunities.

The method of calculating Adjusted EBITDA may not be consistent with that of other companies and each of EBITDA and Adjusted EBITDA has its limitations as an analytical tool, should not be considered in isolation and should be viewed in conjunction with measurements that are computed in accordance with GAAP. Some of the limitations of EBITDA and Adjusted EBITDA are:

•

EBITDA and Adjusted EBITDA do not reflect our cash used for capital expenditures;

•

Although depreciation and amortization are non-cash charges, the assets being depreciated or amortized often will have to be replaced and EBITDA and Adjusted EBITDA do not reflect the cash requirements for such replacements;

•

EBITDA and Adjusted EBITDA do not reflect changes in, or cash requirements for, our working capital requirements;

•

EBITDA and Adjusted EBITDA do not reflect the cash necessary to make payments of interest or principal on our indebtedness; and

•

EBITDA and Adjusted EBITDA do not reflect the cash required to pay taxes.

Customer Attrition

We measure net customer attrition on an ongoing basis for our full service residential and commercial home heating oil and propane customers. Net customer attrition is the difference between gross customer losses and customers added through marketing efforts. Customers added through acquisitions are not included in the calculation of gross customer gains. However, additional customers that are obtained through marketing efforts or lost at newly acquired businesses are included in these calculations. Customer attrition percentage calculations include customers added through acquisitions in the denominators of the calculations on a weighted average basis. Gross customer losses are the result of a number of factors, including price competition, move-outs, credit losses and conversion to natural gas. When a customer moves out of an existing home, we count the “move out” as a loss and, if we are successful in signing up the new homeowner, the “move in” is treated as a gain.

Gross customer gains and gross customer losses


	Nine Months Ended June 30, 2014							Fiscal Year Ended 2013							Fiscal Year Ended 2012
					Net							Net							Net
	Gross Customer				Gains /			Gross Customer				Gains /			Gross Customer				Gains /
	Gains		Losses		(Attrition)			Gains		Losses		(Attrition)			Gains		Losses		(Attrition)
First Quarter		25,700		22,700		3,000			26,100		24,400		1,700			25,700		26,600		(900	)
Second Quarter		16,800		16,700		100			13,900		19,300		(5,400	)		11,500		19,700		(8,200	)
Third Quarter		8,100		14,100		(6,000	)		7,100		13,600		(6,500	)		7,000		13,700		(6,700	)
Fourth Quarter									14,400		18,000		(3,600	)		13,000		18,200		(5,200	)

Total		50,600		53,500		(2,900	)		61,500		75,300		(13,800	)		57,200		78,200		(21,000	)

Net customer gains (attrition) as a percentage of the home heating oil and propane customer base


	Nine Months Ended June 30, 2014⁽¹⁾									Fiscal Year Ended 2013									Fiscal Year Ended 2012
							Net									Net									Net
	Gross Customer						Gains /			Gross Customer						Gains /			Gross Customer						Gains /
	Gains			Losses			(Attrition)			Gains			Losses			(Attrition)			Gains			Losses			(Attrition)
First Quarter		6.2	%		5.5	%		0.7	%		6.3	%		5.9	%		0.4	%		6.2	%		6.4	%		(0.2	%)
Second Quarter		3.9	%		3.9	%		0.0	%		3.3	%		4.6	%		(1.3	%)		2.7	%		4.7	%		(2.0	%)
Third Quarter		1.9	%		3.3	%		(1.4	%)		1.7	%		3.3	%		(1.6	%)		1.5	%		3.1	%		(1.6	%)
Fourth Quarter											3.5	%		4.3	%		(0.8	%)		3.0	%		4.1	%		(1.1	%)

Total		12.0	%		12.7	%		(0.7	%)		14.8	%		18.1	%		(3.3	%)		13.4	%		18.3	%		(4.9	%)

(1)	Percentages have changed slightly from amounts previously reported due to the weighting of the Griffith customer base.

During the first nine months of fiscal 2014, the Partnership’s account base decreased by 2,900 accounts, net, or 7,300 accounts less than the same period of fiscal 2013 in which the Partnership lost 10,200 accounts, net. We believe that the colder-than-expected winter positively impacted our gross customer gains and lowered gross customer losses as competitors could not keep pace with the severe winter conditions. The Partnership cannot predict whether the accounts added during the nine months ended June 30, 2014, will continue to purchase our products.

During the first nine months of fiscal 2014, we lost 1.6% of our home heating oil accounts to natural gas versus 1.7% for the first nine months of fiscal 2013 and 1.5% for the same period of fiscal 2012. Conversions to natural gas have increased in recent years, and we believe this may continue, as natural gas has become significantly less expensive than home heating oil on an equivalent BTU basis. In addition, the states of New York, Connecticut and Pennsylvania have sought to encourage homeowners to expand the use of natural gas as a heating fuel through legislation and regulatory efforts.

Correction of Immaterial Errors

Consolidated Results of Operations

The following is a discussion of the consolidated results of operations of the Partnership and its subsidiaries, and should be read in conjunction with the historical Financial and Operating Data and Notes thereto included elsewhere in this Quarterly Report.

Three Months Ended June 30, 2014

Compared to the Three Months Ended June 30, 2013

Volume

For the three months ended June 30, 2014, retail volume of home heating oil and propane increased by 4.4 million gallons, or 10.4%, to 47.1 million gallons, compared to 42.7 million gallons for the three months ended June 30, 2013. For those locations where the Partnership had existing operations during both periods, which we sometimes refer to as the “base business” (i.e., excluding acquisitions), temperatures (measured on a heating degree day basis) for the three months ended June 30, 2014, were 5.3% warmer than the three months ended June 30, 2013, and 8.9% warmer than normal, as reported by the National Oceanic and Atmospheric Administration (“NOAA”). For the twelve months ended June 30, 2014, net customer attrition for the base business was 1.7%. The volume of home heating oil and propane delivered during the three months ended June 30, 2014, was favorably impacted by the lag effect of colder temperatures experienced in March 2014 versus March 2013. March 2014 was 12.1% colder than March 2013 and as a result, the volume delivered during the three months ended June 30, 2014, was greater than the three months ended June 30, 2013. We believe the impact of this lag effect is included in the table below under the caption “Other.” Due to various reasons, including the significant increase in the price per gallon of home heating oil and propane, we believe that our customers are adopting conservation measures to use less of such products. The impact of any such conservation, along with any period-to-period differences in delivery scheduling, the timing of accounts added or lost during the fiscal years, equipment efficiency and other volume variances not otherwise described, are also included in the chart below under the heading “Other.” An analysis of the change in the retail volume of home heating oil and propane, which is based on management’s estimates, sampling and other mathematical calculations and certain assumptions, is as follows:


(in millions of gallons)	Heating Oil and Propane
Volume - Three months ended June 30, 2013		42.7
Acquisitions		2.8
Impact of warmer temperatures		(2.3	)
Net customer attrition		(0.9	)
Other		4.8

Change		4.4


Volume - Three months ended June 30, 2014		47.1

The following chart sets forth the percentage by volume of total home heating oil sold to residential variable-price customers, residential price-protected customers and commercial/industrial/other customers for the three months ended June 30, 2014, compared to the three months ended June 30, 2013:


	Three Months Ended
Customers	June 30, 2014			June 30, 2013
Residential Variable		38.0	%		39.7	%
Residential Price-Protected		48.0	%		46.9	%
Commercial/Industrial/Other		14.0	%		13.4	%

Total		100.0	%		100.0	%

The Partnership has experienced a shift away from variable pricing plans to price-protected offerings as customers are seeking surety of price, which may impact our ability to expand our per gallon margins in the future.

Volume of other petroleum products increased by 12.2 million gallons, or 93.7%, to 25.3 million gallons for the three months ended June 30, 2014, compared to 13.1 million gallons for the three months ended June 30, 2013, largely due to the additional volume from the Griffith acquisition.

Product Sales

For the three months ended June 30, 2014, product sales increased $58.8 million, or 28.2%, to $267.7 million, compared to $208.9 million for the three months ended June 30, 2013, due to an increase in total volume of 29.9%.

Installations and Service Sales

For the three months ended June 30, 2014, installations and service sales increased $5.1 million, or 9.6%, to $58.8 million, compared to $53.7 million for the three months ended June 30, 2013, as the additional revenue from acquisitions of $5.3 million was slightly reduced by a decline in the base business of $ 0.2 million largely due to an adjustment from prior periods of $0.6 million.

Cost of Product

For the three months ended June 30, 2014, cost of product increased $52.3 million, or 32.0%, to $215.8 million, compared to $163.5 million for the three months ended June 30, 2013, largely due to an increase in total volume of 29.9%.

Gross Profit—Product

The table below calculates the Partnership’s per gallon margins and reconciles product gross profit for home heating oil and propane and other petroleum products. We believe the change in home heating oil and propane margins should be evaluated before the effects of increases or decreases in the fair value of derivative instruments, as we believe that realized per gallon margins should not include the impact of non-cash changes in the market value of hedges before the settlement of the underlying transaction. On that basis, home heating oil and propane margins for the three months ended June 30, 2014, decreased by $0.0273 per gallon, or 2.8%, to $0.9507 per gallon, from $0.9780 per gallon during the three months ended June 30, 2013. However, the margins achieved during the three months ended June 30, 2014, exceeded management’s expectations by approximately $0.0300 per gallon and exceeded the margins achieved during the three months ended June 30, 2012 of $0.9196 by $0.0311 per gallon or an annual increase of 1.7%. The third quarter of the Partnership’s fiscal year is a non heating season quarter and thus the per gallon margins realized during this period are not as impactful on the Partnership’s annual results as the per gallon margins realized during the heating season, due to the low volume sold in the non heating season quarters.


	Three Months Ended
	June 30, 2014				June 30, 2013
Home Heating Oil and Propane	Amount (in millions)		Per Gallon		Amount (in millions)		Per Gallon
Volume		47.1				42.7

Sales	$	184.7	$	3.9205	$	166.6	$	3.9019
Cost	$	139.9	$	2.9698	$	124.8	$	2.9239


Gross Profit	$	44.8	$	0.9507	$	41.7	$	0.9780


Other Petroleum Products	Amount (in millions)		Per Gallon		Amount (in millions)		Per Gallon
Volume		25.3				13.1

Sales	$	83.0	$	3.2821	$	42.3	$	3.2386
Cost	$	75.9	$	3.0020	$	38.7	$	2.9630


Gross Profit	$	7.1	$	0.2801	$	3.6	$	0.2756


Total Product	Amount (in millions)				Amount (in millions)
Sales	$	267.7			$	208.9
Cost	$	215.8			$	163.5


Gross Profit	$	51.9			$	45.3

For the three months ended June 30, 2014, total product gross profit increased by $ 6.6 million to $51.9 million, compared to $45.3 million for the three months ended June 30, 2013, as the impact of increases in home heating oil and propane volume ($4.3 million) and the additional gross profit from other petroleum products ($3.5 million) was partially offset by a decrease in home heating oil and propane margins ($1.2 million). The increase in gross profit from other petroleum products was largely due to the additional volume from the Griffith acquisition.

Cost of Installations and Service

For the three months ended June 30, 2014, cost of installations and service increased by $5.9 million, or 13.4%, to $50.0 million, compared to $44.1 million for the three months ended June 30, 2013, reflecting a $4.7 million increase related to acquisitions and a $1.2 million increase in the base business. During the three month ended June 30, 2014, the Partnership continued to expand its propane operations and as a result, propane service costs increased by $0.3 million. This increase was largely due to labor and sundry costs related to installing new propane tanks at customer’s homes as well as training and start-up costs associated with the expansion of this initiative.

Total installation costs for the three months ended June 30, 2014, increased by $ 1.8 million, or 11.3%, to $17.5 million, compared to $15.7 million for the three months ended June 30, 2013, due to a slight increase in the base business of $0.3 million and an increase from acquisitions of $1.5 million. Installation costs as a percentage of installation sales for the three months ended June 30, 2014, and the three months ended June 30, 2013, were 83.2% and 84.6%, respectively. Service expenses increased to $32.5 million for the three months ended June 30, 2014, or 86.0% of service sales, versus $28.4 million, or 80.9% of service sales, for the three months ended June 30, 2013. We experienced a combined gross profit from service and installation of $8.8 million for the three months ended June 30, 2014, or $0.7 million less than the amount realized of $9.6 million for the three months ended June 30, 2013. While acquisitions provided an increase in service and installation profitability of $0.6 million, this was more than offset by the increase in start-up propane service expenses of $0.3 million and the reduction in installation revenue related to prior periods of $0.6 million. Management views the service and installation department on a combined basis because many overhead functions and direct expenses such as service technician time cannot be separated or precisely allocated to either service or installation billings.

(Increase) Decrease in the Fair Value of Derivative Instruments

During the three months ended June 30, 2014, the change in the fair value of derivative instruments resulted in a $3.3 million credit due to the expiration of certain hedged positions (a $1.6 million credit) and an increase in market value for unexpired hedges (a $1.7 million credit).

During the three months ended June 30, 2013, the change in the fair value of derivative instruments resulted in a $1.9 million charge due to the expiration of certain hedged positions (a $1.5 million credit) and a decrease in the market value for unexpired hedges (a $3.4 million charge).

Delivery and Branch Expenses

For the three months ended June 30, 2014, delivery and branch expenses increased $12.5 million, or 23.3%, to $66.3 million, compared to $53.8 million for the three months ended June 30, 2013, due to higher delivery and branch expenses of $8.2 million from the Griffith acquisition and an increase in bad debt expense of $2.5 million. The latter was related to the higher level of sales in fiscal 2014 in the base business versus fiscal 2013 and the typical payment patterns of customers during the months following the heating season. In addition, during the three months ended June 30, 2014, the Partnership recorded a $1.7 million charge to correct understatements of certain sales and petroleum taxes and related penalties that, while previously contested, all pertained to years prior to fiscal 2014 and should have been recorded in prior periods. Of the $1.7 million, $1.0 million is related to fiscal years 2002 to 2010.

On a cents per gallon basis, delivery and branch expenses for the three months ended June 30, 2014, decreased by $0.0588, or 5.9%, to $0.9363, compared to $0.9951 for the three months ended June 30, 2013, as certain fixed operating expenses were spread over a larger volume base in the latest three months.

Depreciation and Amortization

For the three months ended June 30, 2014, depreciation and amortization expense increased by $ 1.4 million, or 33.1%, to $5.8 million, compared to $4.3 million for the three months ended June 30, 2013. This increase was largely due to the Griffith acquisition.

General and Administrative Expenses

For the three months ended June 30, 2014, general and administrative expenses increased $0.6 million, to $5.1 million, from $4.6 million for the three months ended June 30, 2013, partly due to an increase in profit sharing expense of $0.2 million.

The Partnership accrues approximately 6% of Adjusted EBITDA as defined in the profit sharing plan for distribution to its employees, and this amount is payable when the Partnership achieves Adjusted EBITDA of at least 70% of the amount budgeted. The dollar amount of the profit sharing pool is subject to increases and decreases in line with fluctuations in Adjusted EBITDA.

Finance Charge Income

For the three months ended June 30, 2014, finance charge income increased by $0.8 million to $2.5 million compared to $1.7 million for the three months ended June 30, 2013. This increase was due to acquisition related finance charge income of $0.3 million and an increase in past due accounts receivable balances.

Interest Expense, Net

For the three months ended June 30, 2014, interest expense increased $1.9 million, or 53.5%, to $5.4 million compared to $3.5 million for the three months ended June 30, 2013. An increase in average working capital borrowings of $83.2 million offset by a 1.9% decline in short-term borrowing rates from 4.3% to 2.4% resulted in an increase in interest expense of $0.4 million. In addition, the Partnership recorded a $1.4 million charge to correct understatements arising from certain sales and petroleum tax audits that were previously contested, of which $1.2 million was for years prior to fiscal 2014.

Amortization of Debt Issuance Costs

For the three months ended June 30, 2014, amortization of debt issuance costs was unchanged at $0.4 million compared to the three months ended June 30, 2013.

Income Tax Benefit

For the three months ended June 30, 2014, income tax benefit increased by $2.7 million to $7.0 million from $4.4 million when compared to the three months ended June 30, 2013. The Partnership’s effective income tax rate was 42.3% for the three months ended June 30, 2014, compared to 36.5% for the three months ended June 30, 2013. The increase in the effective tax rate, which increased the Partnership’s tax benefit, was largely due to a non-recurring benefit of $0.5 million related to deferred state taxes recorded in the quarter ending June 30, 2014.

Net Loss

For the three months ended June 30, 2014, net loss increased $2.0 million to $9.6 million, from $7.6 million for the three months ended June 30, 2013, due to an increase in the pretax loss of $4.7 million.

Adjusted EBITDA

For the three months ended June 30, 2014, the Adjusted EBITDA loss increased by $6.6 million to $ 8.3 million as the increase in volume in the base business was reduced by a return to home heating oil and propane margins more in line with those realized in the third quarter of fiscal 2012 rather than the margins realized during the three months ended June 30, 2013 ($1.3 million), an expected increase in bad debt expense of $2.5 million in the base business largely due to fiscal 2014 weather related sales increases and the typical payment patterns of customers during the months subsequent to the completion of the heating season, an increase in service expenses of $ 0.3 million relating to the Partnership’s propane expansion initiative, and adjustments to service and installation sales and delivery and branch expenses aggregating $2.3 million, of which $1.7 million was to correct understatements of certain sales and petroleum taxes and related penalties that, while previously contested, all pertained to years prior to fiscal 2014 and should have been recorded in prior periods. In addition, for the three months ended June 30, 2014, the Griffith acquisition recorded an Adjusted EBITDA loss of $0.8 million which was in line with management’s expectations.

EBITDA and Adjusted EBITDA should not be considered as an alternative to net income (as an indicator of operating performance) or as an alternative to cash flow (as a measure of liquidity or ability to service debt obligations), but provides additional information for evaluating our ability to make the Minimum Quarterly Distribution.

EBITDA and Adjusted EBITDA are calculated as follows:


	Three Months Ended June 30,
(in thousands)	2014			2013

Net loss	$	(9,592	)	$	(7,588	)
Plus:
Income tax benefit		(7,026	)		(4,364	)
Amortization of debt issuance cost		394			415
Interest expense, net		5,427			3,536
Depreciation and amortization		5,760			4,328

EBITDA (i) (a)		(5,037	)		(3,673	)

(Increase) / decrease in the fair value of derivative instruments		(3,308	)		1,910

Adjusted EBITDA (i) (a)		(8,345	)		(1,763	)

Add / (subtract)
Income tax benefit		7,026			4,364
Interest expense, net		(5,427	)		(3,536	)
Provision for losses on accounts receivable		4,384			1,611
Decrease in accounts receivables		161,737			136,636
(Increase) decrease in inventories		11,560			(7,334	)
Increase in customer credit balances		8,837			9,670
Change in deferred taxes		861			(4,359	)
Change in other operating assets and liabilities		(53,680	)		(25,550	)

Net cash provided by operating activities	$	126,953		$	109,739



Net cash used in investing activities	$	(1,471	)	$	(1,551	)



Net cash used in financing activities	$	(131,322	)	$	(74,374	)

(i)	Fiscal year 2013 operating income, EBITDA and Adjusted EBITDA have been revised to reflect the reclassification of finance charge income from interest expense, net.

(a)

•

our compliance with certain financial covenants included in our debt agreements;

•

our financial performance without regard to financing methods, capital structure, income taxes or historical cost basis;

•

our ability to generate cash sufficient to pay interest on our indebtedness and to make distributions to our partners;

•

the viability of acquisitions and capital expenditure projects and the overall rates of return of alternative investment opportunities.

•

EBITDA and Adjusted EBITDA do not reflect our cash used for capital expenditures.

•

EBITDA and Adjusted EBITDA do not reflect changes in, or cash requirements for, our working capital requirements;

•

EBITDA and Adjusted EBITDA do not reflect the cash necessary to make payments of interest or principal on our indebtedness; and

•

EBITDA and Adjusted EBITDA do not reflect the cash required to pay taxes.

Nine Months Ended June 30, 2014

Compared to the Nine Months Ended June 30, 2013

Volume

For the nine months ended June 30, 2014, retail volume of home heating oil and propane increased by 34.5 million gallons, or 11.4%, to 338.7 million gallons, compared to 304.2 million gallons for the nine months ended June 30, 2013. For those locations where the Partnership had existing operations during both periods, which we sometimes refer to as the “base business” (i.e., excluding acquisitions), temperatures (measured on a heating degree day basis) for the nine months ended June 30, 2014, were 9.2% colder than the nine months ended June 30, 2013, and 4.9% colder than normal, as reported by the National Oceanic and Atmospheric Administration (“NOAA”). For the twelve months ended June 30, 2014, net customer attrition for the base business was 1.7%. In addition, aside from the impact of colder weather, deliveries of home heating oil and propane were greater in the nine months ended June 30, 2014, than the nine months ended June 30, 2013, due to the impact of storm Sandy on deliveries in fiscal 2013. Certain of our customers were without power for several weeks subsequent to Sandy, which reduced their consumption during that period. The home heating oil and propane volume impact due to Sandy is included in the chart below under the heading “Other.” For various reasons, including the significant increase in the price per gallon of home heating oil and propane, we believe that our customers are adopting conservation measures to use less of such products. The impact of any such conservation, along with any period-to-period differences in delivery scheduling, the timing of accounts added or lost during the fiscal years, equipment efficiency and other volume variances not otherwise described, are also included in the chart under the heading “Other.” An analysis of the change in the retail volume of home heating oil and propane, which is based on management’s estimates, sampling and other mathematical calculations and certain assumptions, is as follows:


(in millions of gallons)	Heating Oil and Propane
Volume - Nine months ended June 30, 2013		304.2
Acquisitions		8.1
Impact of colder temperatures		26.9
Net customer attrition		(8.1	)
Other		7.6

Change		34.5


Volume - Nine months ended June 30, 2014		338.7

The following chart sets forth the percentage by volume of total home heating oil sold to residential variable-price customers, residential price-protected customers and commercial/industrial/other customers for the nine months ended June 30, 2014, compared to the nine months ended June 30, 2013:


	Nine Months Ended
Customers	June 30, 2014			June 30, 2013
Residential Variable		40.0	%		41.8	%
Residential Price-Protected		45.9	%		44.3	%
Commercial/Industrial/Other		14.1	%		13.9	%

Total		100.0	%		100.0	%

The Partnership has experienced a shift away from variable pricing plans to price-protected plans as customers are seeking surety of price which may impact our per gallon margins in the future.

Volume of other petroleum products increased by 13.9 million gallons, or 30.3%, to 59.9 million gallons for the nine months ended June 30, 2014, compared to 46.0 million gallons for the nine months ended June 30, 2013, largely due to the additional volume from the Griffith acquisition of 16.2 million gallons, partially offset by a decline in the base business of 2.3 million gallons. In the prior year’s comparable period, the Partnership experienced an increase in motor fuel demand as a result of Sandy.

Product Sales

For the nine months ended June 30, 2014, product sales increased $174.8 million, or 12.5%, to $1.6 billion, compared to $1.4 billion for the nine months ended June 30, 2013, primarily due to an increase in total volume of 13.8%.

Installations and Service Sales

For the nine months ended June 30, 2014, installations and service sales increased $0.4 million, or 0.3%, to $168.3 million, compared to $167.9 million for the nine months ended June 30, 2013, as additional revenue of $7.3 million from acquisitions was nearly offset by a decrease in the base business of $6.9 million. In the prior year’s comparable period, installation and service billings were favorably impacted by Sandy-related demand.

Cost of Product

For the nine months ended June 30, 2014, cost of product increased $122.0 million, or 11.2%, to $1.2 billion, compared to $1.1 billion for the nine months ended June 30, 2013, largely due to an increase in total volume of 13.8%.

Gross Profit—Product

The table below calculates the Partnership’s per gallon margins and reconciles product gross profit for home heating oil and propane and other petroleum products. We believe the change in home heating oil and propane margins should be evaluated before the effects of increases or decreases in the fair value of derivative instruments, as we believe that realized per gallon margins should not include the impact of non-cash changes in the market value of hedges before the settlement of the underlying transaction. On this basis, home heating oil and propane margins for the nine months ended June 30, 2014, increased by $0.0477 per gallon, or 5.0%, to $1.0044 per gallon, from $0.9567 per gallon during the nine months ended June 30, 2013. Over the last four fiscal years, home heating oil and propane margins have increased by $0.0143 cents per gallon on average per year. The expansion of the Partnerships margins during the nine months June 30, 2014, was in excess of this historical average by $0.0365 cents per gallon. During this period, the Partnership was able to take advantage of certain market conditions which enabled it to expand margins further. In addition, numerous snow storms, which drove an increase in operating and service costs, necessitated an increase in selling prices to defray additional operating costs. Going forward, the Partnership cannot predict whether the per gallon margins achieved during the nine months ended June 30, 2014, are sustainable. Product sales and cost of product include home heating oil, propane, other petroleum products and liquidated damages billings.


	Nine Months Ended
	June 30, 2014				June 30, 2013
Home Heating Oil and Propane	Amount (in millions)		Per Gallon		Amount (in millions)		Per Gallon
Volume		338.8				304.2

Sales	$	1,370.1	$	4.0446	$	1,237.6	$	4.0683
Cost	$	1,029.9	$	3.0402	$	946.6	$	3.1116


Gross Profit	$	340.3	$	1.0044	$	291.0	$	0.9567


Other Petroleum Products	Amount (in millions)		Per Gallon		Amount (in millions)		Per Gallon
Volume		59.9				46.0

Sales	$	200.9	$	3.3546	$	158.7	$	3.4521
Cost	$	184.1	$	3.0739	$	145.4	$	3.1624


Gross Profit	$	16.8	$	0.2808	$	13.3	$	0.2897


Total Product	Amount (in millions)				Amount (in millions)
Sales	$	1,571.0			$	1,396.3
Cost	$	1,214.0			$	1,091.9


Gross Profit	$	357.1			$	304.4

For the nine months ended June 30, 2014, total product gross profit increased by $52.7 million to $357.1 million, compared to $304.4 million for the nine months ended June 30, 2013, due to an increase in home heating oil and propane volume ($33.0 million), the impact of higher home heating oil and propane margins ($16.2 million) and the additional gross profit from other petroleum products ($3.5 million). The increase in gross profit from other petroleum products was largely due to the additional volume from the Griffith acquisition, reduced by a decline in the base business. In the prior year’s comparable period, the Partnership experienced an increase in motor fuel demand as a result of Sandy.

Cost of Installations and Service

For the nine months ended June 30, 2014, cost of installations and service increased by $3.8 million, or 2.5%, to $156.5 million, compared to $152.7 million for the nine months ended June 30, 2013, as a $6.6 million increase related to acquisitions was slightly offset by a $2.8 million reduction in our base business. While service costs rose in the base business due to the additional service costs associated with 9.2% colder temperatures as well as the Partnership’s continued expansion of its propane operations ($0.9 million), these increases were more than offset by lower service and installation costs versus the prior year’s comparable period included costs that were Sandy-related.

Installation costs for the nine months ended June 30, 2014, decreased by $2.6 million, or 4.7%, to $51.5 million, compared to $54.1 million in installation costs for the nine months ended June 30, 2013, as a decline in the base business of $4.7 million was only partially reduced by an increase from acquisitions of $2.1 million. Installation costs as a percentage of installation sales for the nine months ended June 30, 2014, and the nine months ended June 30, 2013, were 84.6% and 84.2%, respectively. Service expenses increased to $104.9 million for the nine months ended June 30, 2014, or 97.7% of service sales, versus $98.5 million, or 95.1% of service sales, for the nine months ended June 30, 2013. We achieved a combined profit from service and installation of $11.8 million for the nine months ended June 30, 2014, or $3.4 million less than a combined profit of $15.2 million for the nine months ended June 30, 2013. While Griffith provided $0.7 million of gross profit from service and installation activities, the decline in the base business was largely due to lower service

and installation work versus the prior year which benefited from Sandy, an increase in service costs resulting from colder temperatures and $0.9 million of additional costs associated with the Partnership’s propane initiative. Management views the service and installation department on a combined basis because many overhead functions and direct expenses such as service technician time cannot be separated or precisely allocated to either service or installation billings.

(Increase) Decrease in the Fair Value of Derivative Instruments

During the nine months ended June 30, 2014, the change in the fair value of derivative instruments resulted in a $4.7 million credit due to the expiration of certain hedged positions (a $5.8 million credit) and a decrease in market value for unexpired hedges (a $1.1 million charge).

During the nine months ended June 30, 2013, the change in the fair value of derivative instruments resulted in a $6.4 million charge due to the expiration of certain hedged positions (a $1.0 million charge) and a decrease in the market value for unexpired hedges (a $5.4 million charge).

Delivery and Branch Expenses

For the nine months ended June 30, 2014, delivery and branch expense increased $21.7 million, or 10.5%, to $227.2 million, compared to $205.5 million for the nine months ended June 30, 2013, due to the increase in total volume sold of 13.8%, including acquisitions, higher sales and marketing expenses of $1.8 million related to improved net customer attrition and an increase in the reserve for bad debts of $1.0 million tied to the increase in sales. In addition, during the nine months ended June 30, 2014, the Partnership recorded a $1.7 million charge to correct understatements of certain sales and petroleum taxes and related penalties that, while previously contested, all pertained to years prior to fiscal 2014 and should have been recorded in prior periods, including $1.0 million related to fiscal years 2002 through 2010.

On a cents per gallon basis, delivery and branch expenses for the nine months ended June 30, 2014, decreased $0.0190, or 3.1%, to $0.5874, compared to $0.6064 for the nine months ended June 30, 2013, as certain fixed operating expenses were spread over a larger volume base in the current period.

Depreciation and Amortization

For the nine months ended June 30, 2014, depreciation and amortization expenses increased by $2.0 million, or 15.6%, to $15.0 million, compared to $13.0 million for the nine months ended June 30, 2013, largely due to the Griffith acquisition.

General and Administrative Expenses

For the nine months ended June 30, 2014, general and administrative expenses increased $3.2 million, or 23.1%, to $17.0 million, from $13.8 million for the nine months ended June 30, 2013, primarily due to an increase in profit sharing expense of $1.4 million, higher acquisition- related expenses of $0.6 million largely due to the Griffith acquisition and an increase in legal and professional fees of $0.5 million.

Finance Charge Income

For the nine months ended June 30, 2014, finance charge income increased $0.8 million to $5.7 million, compared to $4.9 million for the nine months ended June 30, 2013. This increase was due to acquisition related finance charge income of $0.4 million and an increase in past due account balances.

Interest Expense, Net

For the nine months ended June 30, 2014, interest expense increased $2.3 million, or 21.5%, to $13.3 million compared to the $11.0 million for the nine months ended June 30, 2013. An increase in average working capital borrowings of $60.7 million was reduced by a 1.2% decline in short-term borrowing rates from 3.8% to 2.6%. In addition, the Partnership recorded a $1.2 million charge to correct understatements arising from certain sales and petroleum tax audits that were previously contested.

Amortization of Debt Issuance Costs

For the nine months ended June 30, 2014, amortization of debt issuance costs decreased by $0.1 million to $1.2 million, compared to $1.3 million for the nine months ended June 30, 2013.

Income Tax Expense

For the nine months ended June 30, 2014, income tax expense increased by $13.9 million to $43.6 million from $29.7 million for the nine months ended June 30, 2013, due to an increase in pretax income of $32.0 million.

Net Income

For the nine months ended June 30, 2014, net income increased $18.1 million to $61.9 million, from $43.8 million for the nine months ended June 30, 2013, as the increase in pretax income of $32.0 million was greater than the increase in income tax expense of $13.9 million.

Adjusted EBITDA

For the nine months ended June 30, 2014, Adjusted EBITDA increased by $25.2 million, or 23.9%, to $130.4 million as the impact of the increase in home heating oil and propane volume primarily due to 9.2% colder temperatures, higher home heating oil and propane per gallon margins and $3.2 million in Adjusted EBITDA generated by acquisitions, including $2.4 million from Griffith, more than offset the favorable impact in the prior year’s period of storm Sandy on motor fuel sales and service and installation revenue, higher operating and service costs largely attributable to the colder temperatures and the numerous snow storms during the nine months ended June 30, 2014, and an increase in bad debt expense driven largely by the severe winter weather during fiscal 2014. Other negative impacts of $3.4 million on Adjusted EBITDA during the nine months ended June 30, 2014, included $0.8 million of higher service and installation costs attributable to propane growth, $0.6 million of acquisition related legal and professional expenses tied to the Griffith acquisition, and adjustments to service and installation sales and delivery and branch expenses of $2.0 million, of which $1.7 million was to correct understatements of certain sales and petroleum taxes and related penalties that, while previously contested, all pertained to years prior to fiscal 2014 and should have been recorded in prior periods.

EBITDA and Adjusted EBITDA are calculated as follows:


	Nine Months Ended June 30,
(in thousands)	2014			2013

Net income	$	61,912		$	43,843
Plus:
Income tax expense		43,602			29,670
Amortization of debt issuance cost		1,205			1,325
Interest expense, net		13,324			10,967
Depreciation and amortization		15,036			13,007

EBITDA (i) (a)		135,079			98,812

(Increase) / decrease in the fair value of derivative instruments		(4,661	)		6,428

Adjusted EBITDA (i) (a)		130,418			105,240

Add / (subtract)
Income tax expense		(43,602	)		(29,670	)
Interest expense, net		(13,324	)		(10,967	)
Provision for losses on accounts receivable		8,862			7,814
Increase in accounts receivables		(78,276	)		(71,929	)
Decrease (increase) in inventories		24,706			(1,585	)
Decrease in customer credit balances		(43,588	)		(52,719	)
Change in deferred taxes		9,051			4,292
Change in other operating assets and liabilities		11,006			17,894

Net cash provided by (used in) operating activities	$	5,253		$	(31,630	)



Net cash used in investing activities	$	(104,321	)	$	(3,644	)



Net cash provided by (used in) financing activities	$	21,126		$	(28,435	)

(i)	Fiscal year 2013 operating income, EBITDA and Adjusted EBITDA have been revised to reflect the reclassification of finance charge income from interest expense, net.

(a)

•

our compliance with certain financial covenants included in our debt agreements;

•

our financial performance without regard to financing methods, capital structure, income taxes or historical cost basis;

•

our ability to generate cash sufficient to pay interest on our indebtedness and to make distributions to our partners;

•

the viability of acquisitions and capital expenditure projects and the overall rates of return of alternative investment opportunities.

•

EBITDA and Adjusted EBITDA do not reflect our cash used for capital expenditures.

•

EBITDA and Adjusted EBITDA do not reflect changes in, or cash requirements for, our working capital requirements;

•

EBITDA and Adjusted EBITDA do not reflect the cash necessary to make payments of interest or principal on our indebtedness; and

•

EBITDA and Adjusted EBITDA do not reflect the cash required to pay taxes.

DISCUSSION OF CASH FLOWS

We use the indirect method to prepare our Consolidated Statements of Cash Flows. Under this method, we reconcile net income to cash flows provided by operating activities by adjusting net income for those items that impact net income but do not result in actual cash receipts or payment during the period.

Operating Activities

Due to the seasonal nature of our business, cash is generally used in operations during the winter (our first and second fiscal quarters) as we require additional working capital to support the high volume of sales during this period, and cash is generally provided by operating activities during the spring and summer (our third and fourth quarters) when customer payments exceed the cost of deliveries.

For the nine months ended June 30, 2014, cash provided by operating activities was $5.3 million, or $36.9 million greater than cash used in operating activities for the nine months ended June 30, 2013, of $31.6 million. Cash generated from operations in fiscal 2014 increased by $14.7 million largely due to the impact of colder weather, and cash used to finance accounts receivable, including customers on our budget payment plans, decreased by $2.8 million. As of June 30, 2014 (excluding the recently completed Griffith acquisition), days sales outstanding were 64.0 days compared to 56.1 days as of June 30, 2013, and 48.4 days as of June 30, 2012. The driver of the increase in days sales outstanding largely relates to amounts due from customers on a budget plan, where volumes exceeded the expectations used to determine the monthly budget payments. In addition, to take advantage of market conditions at September 30, 2013, the Partnership had increased inventory quantities by the beginning of fiscal 2014 to a much greater extent than by the beginning of fiscal 2013. As a result, cash used to finance inventory purchases was $26.3 million less during the nine months ended June 30, 2014, than the nine months ended June 30, 2013. The timing of certain accruals and payments, including income taxes, insurance and amounts due under the Partnership’s profit sharing plan also provided $6.9 million more cash for the nine months ended June 30, 2014, compared to the nine months ended June 30, 2013.

Investing Activities

Our capital expenditures for the nine months ended June 30, 2014, totaled $6.5 million, as we invested in computer hardware and software ($1.3 million), refurbished certain physical plants ($1.2 million), expanded our propane operations ($2.4 million) and made additions to our fleet and other equipment ($1.6 million). We also completed the Griffith acquisition for $98.7 million and allocated $52.4 million of the gross purchase price to intangible assets (including $8.0 million to goodwill), $17.5 million to fixed assets, $1.8 million to other long-term assets and $27.1 million to working capital, net of cash acquired of $4.2 million.

Our capital expenditures for the nine months ended June 30, 2013, totaled $3.1 million, as we invested in computer hardware and software ($0.7 million), refurbished certain physical plants ($0.5 million), expanded our propane operations ($1.4 million) and made additions to our fleet and other equipment ($0.5 million). We also completed one acquisition for $0.6 million.

Financing Activities

During the nine months ended June 30, 2014, we borrowed $195.4 million under our revolving credit facility and repaid $155.9 million. We also paid distributions of $14.51 million to our Common Unit holders, $0.23 million to our General Partner unit holders (including $0.16 million of incentive distributions as provided in our Partnership Agreement) and repurchased 0.25 million units for $1.3 million in connection with our unit repurchase plan. We extended our bank facilities and paid $2.4 million in fees.

During the nine months ended June 30, 2013, we borrowed $111.5 million under our revolving credit facility and subsequently repaid $111.5 million. We also paid distributions of $14.3 million to our Common Unit holders, $0.2 million to our General Partner unit holders (including $0.1 million of incentive distributions as provided in our Partnership Agreement) and repurchased 3.0 million units for $13.9 million in connection with our unit repurchase plan.

FINANCING AND SOURCES OF LIQUIDITY

Liquidity and Capital Resources

Our primary uses of liquidity are to provide funds for our working capital, capital expenditures, distributions on our units, acquisitions and unit repurchases. Our ability to provide funds for such uses depends on our future performance, which will be subject to prevailing economic, financial, business and weather conditions, the ability to pass on the full impact of high product costs to customers, the effects of high net customer attrition, conservation and other factors. Capital requirements, at least in the near term, are expected to be provided by cash flows from operating activities, cash on hand as of June 30, 2014, ($7.1 million) or a combination thereof. To the extent future capital requirements exceed cash on hand plus cash flows from operating activities, we anticipate that working capital will be financed by our revolving credit facility, as discussed below, and repaid from subsequent seasonal reductions in inventory and accounts receivable. If we require additional capital and the markets are receptive, we may seek to offer and sell debt or equity securities in public or private offerings.

In January 2014 we entered into a second amended and restated asset-based revolving credit facility, which expires in June 2017 or in January 2019 if certain conditions have been met (see Note 9(c)), and which provides us with the ability to borrow up to $300 million ($450 million during the heating season from December through April of each year) for working capital purposes (subject to certain borrowing base limitations and coverage ratios), including the issuance of up to $100 million in letters of credit. We can increase the facility size by $100 million without the consent of the bank group. However, the bank group is not obligated to fund the $100 million increase. If the bank group elects not to fund the increase, we can add additional lenders to the group with the consent of the Agent which shall not be unreasonably withheld. Obligations under the revolving credit facility are guaranteed by us and our subsidiaries and secured by liens on substantially all of our assets, including accounts receivable, inventory, general intangibles, real property, fixtures and equipment. As of June 30, 2014, there were $39.5 million in borrowings under our revolving credit facility and $52.5 million in letters of credit outstanding, primarily for current and future insurance reserves.

Under the terms of the revolving credit facility, we must maintain at all times either Availability (borrowing base less amounts borrowed and letters of credit issued) of 12.5% of the facility size or a fixed charge coverage ratio of not less than 1.1, which is calculated based upon Adjusted EBITDA for the trailing twelve month period. As of June 30, 2014, Availability, as defined in the revolving credit facility agreement, was $120.9 million and the fixed charge coverage ratio for the twelve months ended June 30, 2014, was in excess of 1.1.

Maintenance capital expenditures for the remainder of fiscal 2014 are estimated to be approximately $1.5 to $2.0 million, excluding the capital requirements for leased fleet. In addition, we plan to invest an estimated $1.0 million in our propane operations. Distributions during the remainder of fiscal 2014 at the current quarterly level of $0.0875 per unit (subject to the Board’s quarterly determination of the amount of Available Cash), will aggregate approximately $5.1 million to Common Unit holders, $0.086 million to our General Partner (including $0.064 million of incentive distribution as provided in our Partnership Agreement) and $0.064 million to management pursuant to the management incentive compensation plan which provides for certain members of management to receive incentive distributions that would otherwise be payable to the General Partner. Based upon certain actuarial assumptions, we estimate that the Partnership will make cash contributions to its frozen defined benefit pension obligations totaling approximately $0.6 million for the remainder of fiscal 2014.

Contractual Obligations and Off-Balance Sheet Arrangements

There has been no material change to Contractual Obligations and Off-Balance Sheet Arrangements since our September 30, 2013, Form 10-K disclosure and therefore, the table has not been included in this Form 10-Q.

Recent Accounting Pronouncements

The following new accounting standard is currently being evaluated by the Partnership, and is more fully described in Note 2. Summary of Significant Accounting Policies - Recent Accounting Pronouncements, of the consolidated financial statements:

•

ASU No. 2014-09, Revenue from Contracts with Customers.

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

We are exposed to interest rate risk primarily through our bank credit facilities. We utilize these borrowings to meet our working capital needs.

At June 30, 2014, we had outstanding borrowings totaling $164.5 million, of which approximately $39.5 million is subject to variable interest rates under our revolving credit facility. In the event that interest rates associated with this facility were to increase 100 basis points, the after tax impact on future cash flows would be a decrease of $0.2 million.

We also use derivative financial instruments to manage our exposure to market risk related to changes in the current and future market price of home heating oil. The value of market sensitive derivative instruments is subject to change as a result of movements in market prices. Sensitivity analysis is a technique used to evaluate the impact of hypothetical market value changes. Based on a hypothetical ten percent increase in the cost of product at June 30, 2014, the fair market value of these outstanding derivatives would increase by $28.2 million to a value of $28.7 million; and conversely a hypothetical ten percent decrease in the cost of product would decrease the fair market value of these outstanding derivatives by $15.8 million to a negative value of $(15.3) million.

Item 4.

Controls and Procedures

(a) Evaluation of disclosure controls and procedures.

In the third quarter of fiscal 2014, management became aware that a regional zone controller overrode controls over reporting to senior management certain state sales tax and petroleum tax assessments which primarily related to prior periods. The same employee also overrode certain reconciliation controls related to the accuracy and existence of installations and service sales and accounts receivable of an insignificant business (the “Impacted Business”) whose balances and results are maintained on an offline ledger and periodically transferred to the Partnership’s general ledger. This employee’s actions were in violation of the Partnership’s established control policies and procedures. These control deficiencies did not result in a material misstatement to the Partnership’s consolidated financial statements for any periods through and including the fiscal year ended September 30, 2013, or unaudited condensed consolidated financial statements for the first two fiscal quarters of 2014. The correction of these errors was recognized in our unaudited condensed consolidated financial statements for the quarter ended June 30, 2014.

The General Partner’s chief executive officer and its chief financial officer evaluated the effectiveness of the Partnership’s disclosure controls and procedures (as that term is defined in Rule 13a-15(e) of the Securities Exchange Act of 1934, as amended) as of June 30, 2014. Such chief executive officer and chief financial officer concluded that, as a result of the material weakness in internal control over financial reporting described below, our disclosure controls and procedures were not effective as of June 30, 2014. Management reevaluated its previous conclusions on the effectiveness of our disclosure controls and procedures as of September 30, 2013, December 31, 2013, and March 31, 2014, and determined that the material weakness described below also existed as of that date. The Partnership is amending Item 9A of its Annual Report on Form 10-K for 2013, as well as Item 4 of its Quarterly Reports on Form 10-Q for the first and second quarters of fiscal 2014 to reflect the conclusion by management that there was a material weakness in internal control over financial reporting as of the end of the periods covered by these reports.

For purposes of Rule 13a-15(e), the term disclosure controls and procedures means controls and other procedures of an issuer that are designed to ensure that information required to be disclosed by the issuer in the reports that it files or submits under the Act (15 U.S.C. 78a et seq.) is recorded, processed, summarized and reported within the time periods specified in the Commission’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Act is accumulated and communicated to the issuer’s management, including its chief executive officer and chief financial officer, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

(b) Change in Internal Control over Financial Reporting.

Management has identified no changes in internal control during the three months ended June 30, 2014. In connection with our assessment of the effectiveness of internal control over financial reporting at our last assessment date, September 30, 2013, we identified the following deficiencies which constituted a material weakness in our internal control related to financial reporting:

•

Ineffective design and operation of controls related to the recognition and measurement of certain state sales and petroleum tax assessments, including the communication of those assessments by the regional zone controller to senior management. The Partnership did not have an independent monitoring control in place to ensure that these controls were working effectively.

•

Ineffective operation of account reconciliation controls over installations and service sales and accounts receivable of the Impacted Business, where the same regional zone controller did not adequately investigate certain reconciling items, and did not timely communicate them to senior management.

These control deficiencies resulted in errors in installations and service sales, delivery and branch expenses, interest expense, net, current assets, accrued expenses and other current liabilities. These errors did not, individually or in the aggregate, result in a material misstatement to the Partnership’s consolidated financial statements for any periods through and including the fiscal year ended September 30, 2013, and unaudited condensed consolidated financial statements for the first two fiscal quarters of 2014. The correction of these errors was recognized in our condensed consolidated financial statements for the quarter ended June 30, 2014. However such control deficiencies could have resulted in a material misstatement to our annual or interim consolidated financial statements that would not be prevented or detected. Accordingly, management has determined that the override of certain process level and information reporting controls and the lack of an independent control in place to reconcile the state sales and petroleum tax returns with the Partnership’s books and records constituted a material weakness in the aggregate.

In the fourth quarter of fiscal 2014, management became actively engaged in the planning for, and implementation of, remediation efforts to address the material weakness in our internal control over financial reporting identified above. Management has implemented or intends to implement additional controls surrounding the collection, recording and remittance of non-income related taxes and to reinforce the certification process to emphasize senior manager’s accountability for, and commitment to maintaining an ethical environment.

Management believes the measures described above and others that will be implemented will remediate the material weakness that we have identified. As management continues to evaluate and improve internal control over financial reporting, we may decide to take additional measures to address control deficiencies or determine to modify, or in appropriate circumstances not to complete, certain of the remediation measures contemplated.

Nonetheless, the chief executive officer and chief financial officer believe that the subsequent procedures we performed in connection with our preparation of this Form 10-Q provide reasonable assurance that the identified material weakness did not lead to material misstatements in our condensed consolidated financial statements presented in this Form 10-Q or prior periods and that the condensed consolidated financial statements included in this Form 10-Q fairly present, in all material respects, our financial position, results of operations and cash flows as of the dates, and for the periods presented, in accordance with U.S. GAAP.

(d) Other

The General Partner and the Partnership do not expect that our disclosure controls and procedures or our internal control over financial reporting will certainly prevent all fraud and material errors. An internal control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations on all internal control systems, our internal control system can provide only reasonable assurance of achieving its objectives and no evaluation of controls can provide absolute assurance that all control issues and occurrences of fraud, if any, within our Partnership have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple errors or mistakes. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of internal control is also based in part upon certain assumptions about the likelihood of future events, and can provide only reasonable, not absolute, assurance that any design will succeed in achieving its stated goals under all potential future conditions. Over time, controls may become inadequate because of changes in circumstances, or the degree of compliance with the policies and procedures may deteriorate.

PART II OTHER INFORMATION

Item 1.

Legal Proceedings

In the opinion of management, we are not a party to any litigation, which individually or in the aggregate could reasonably be expected to have a material adverse effect on our results of operations, financial position or liquidity.

Item 1A.

Risk Factors

In addition to the other information set forth in this Report, investors should carefully review and consider the information regarding certain factors which could materially affect our business, results of operations, financial condition and cash flows set forth below and in Part I Item 1A. “Risk Factors” in our Fiscal 2013 Form 10-K. We may disclose changes to such factors or disclose additional factors from time to time in our future filings with the SEC.

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

Not applicable.

Item 6.

Exhibits

(a)	Exhibits Included Within:



31.1		Certification of Chief Executive Officer, Star Gas Partners, L.P., pursuant to Rule 13a-14(a)/15d-14(a).

31.2		Certification of Chief Financial Officer, Star Gas Partners, L.P., pursuant to Rule 13a-14(a)/15d-14(a).

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

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

101		The following materials from the Star Gas Partners, L.P. Quarterly Report on Form 10-Q for the quarter ended June 30, 2014, formatted in Extensible Business Reporting Language (XBRL): (i) the Condensed Consolidated Balance Sheets, (ii) the Condensed Consolidated Statements of Operations, (iii) the Condensed Consolidated Statements of Comprehensive Income, (iv) the Condensed Consolidated Statements of Partners’ Capital, (v) the Condensed Consolidated Statements of Cash Flows and (vi) related notes.

101.INS		XBRL Instance Document.

101.SCH		XBRL Taxonomy Extension Schema Document.

101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document.

101.LAB		XBRL Taxonomy Extension Label Linkbase Document.

101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document.

101.DEF		XBRL Taxonomy Extension Definition Linkbase Document.

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrants have duly caused this report to be signed on its behalf of the undersigned thereunto duly authorized:


Star Gas Partners, L.P.
(Registrant)

By:		Kestrel Heat LLC AS GENERAL PARTNER


Signature	Title	Date

/s/ Richard F. Ambury Richard F. Ambury	Executive Vice President, Chief Financial Officer, Treasurer and Secretary Kestrel Heat LLC (Principal Financial Officer)	August 1, 2014

Signature	Title	Date


/s/ Richard G. Oakley Richard G. Oakley	Senior Vice President - Controller Kestrel Heat LLC (Principal Accounting Officer)	August 1, 2014

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