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 ~~March~~June 3130, 2011

¨	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

Commission File Number: 333-103873-01

STAR GAS PARTNERS, L.P.

STAR GAS FINANCE COMPANY

(Exact name of registrants as specified in its charters)


Delaware		06-1437793
Delaware		75-3094991
(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

(Registrants’ telephone number, including area code)

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

Indicate by check mark whether the registrants (1) have 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) have 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 ¨ No ¨

* The registrant has not yet been phased into the interactive data requirements.

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):


Large accelerated filer	¨	Accelerated filer	x
Non-accelerated filer	¨	Smaller reporting company	¨

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

At ~~April~~July 3031, 2011, the registrants had units and shares of each issuer’s classes of common stock outstanding as follows:


Star Gas Partners, L.P.	Common Units	67,077,553
Star Gas Partners, L.P.	General Partner Units	325,729
Star Gas Finance Company	Common Shares	100

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 March 31, 2011 (unaudited) and September 30, 2010		3
Condensed Consolidated Balance Sheets as of June 30, 2011 (unaudited) and September 30, 2010		3
Condensed Consolidated Statements of Operations for the three and six months ended March 31, 2011 and March 31, 2010 (unaudited)		4
Condensed Consolidated Statements of Operations for the three and nine months ended June 30, 2011 and June 30, 2010 (unaudited)		4
Condensed Consolidated Statement of Partners’ Capital and Comprehensive Income for the six months ended March 31, 2011 (unaudited)		5
Condensed Consolidated Statement of Partners’ Capital and Comprehensive Income for the nine months ended June 30, 2011 (unaudited)		5
Condensed Consolidated Statements of Cash Flows (unaudited) for the six months ended March 31, 2011 and March 31, 2010		6
Condensed Consolidated Statements of Cash Flows (unaudited) for the nine months ended June 30, 2011 and June 30, 2010		6
Notes to Condensed Consolidated Financial Statements (unaudited)		7-1817
Item 2—Management’s Discussion and Analysis of Financial Condition and Results of Operations		1918-3844
Item 3—Quantitative and Qualitative Disclosures About Market Risk		3844
Item 4—Controls and Procedures		3845
Part II Other Information:
Item 1—Legal Proceedings		3947
Item 1A—Risk Factors		3947
Item 2— Unregistered Sales of Equity Securities and Use of Proceeds		3947
Item 6—Exhibits		3947
Signatures		4049

STAR GAS PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands)	~~March~~June 3130,2011			September 30,2010
	(unaudited)
ASSETS
Current assets
Cash and cash equivalents	$	1150,~~820~~537		$	61,062
Receivables, net of allowance of $11,177 and $5,443, respectively		275,699			70,443
Receivables, net of allowance of $11,674 and $5,443, respectively		153,809			70,443
Inventories		3960,~~216~~391			66,734
Fair asset value of derivative instruments		2610,~~264~~306			7,158
Current deferred tax asset, net		37,~~106~~022			20,247
Prepaid expenses and other current assets		3120,~~386~~687			21,219
Total current assets		~~387~~302,~~491~~752			246,863
Property and equipment, net		44,~~493~~475			44,712
Goodwill		198,~~845~~953			199,052
Intangibles, net		53,~~821~~705			58,894
Long-term deferred tax asset, net		513,~~261~~451			26,551
Deferred charges and other assets, net		810,~~641~~423			6,436
Total assets	$	~~698~~623,~~552~~759		$	582,508
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities
Accounts payable	$	2214,~~725~~111		$	16,626
Revolving credit facility borrowings		31,593			—
Fair liability value of derivative instruments		—			1,586
Accrued expenses and other current liabilities		9682,~~660~~936			68,854
Unearned service contract revenue		4440,~~308~~696			40,110
Customer credit balances		1623,~~633~~429			68,762
Total current liabilities		~~211~~161,~~919~~172			195,938
Long-term debt		124,~~219~~241			82,770
Other long-term liabilities		2221,~~618~~600			23,889
Partners’ capital
Common unitholders		~~365~~342,~~934~~627			307,092
General partner		~~525~~378			290
Accumulated other comprehensive loss, net of taxes		(26,~~663~~259	)		(27,471	)
Total partners’ capital		~~339~~316,~~796~~746			279,911
Total liabilities and partners’ capital	$	~~698~~623,~~552~~759		$	582,508

See accompanying notes to condensed consolidated financial statements.

STAR GAS PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

	Three Months Ended March 31,						Six Months Ended March 31,
	Three Months EndedJune 30,						Nine Months EndedJune 30,
(in thousands, except per unit data - unaudited)	2011			2010			2011			2010
Sales:
Product	$	~~686~~198,~~452~~450		$	~~510~~130,~~713~~168		$	1,~~091~~289,~~420~~870		$	~~812~~942,~~478~~646
Installations and service		4548,~~413~~322			4146,~~019~~593			99148,~~946~~268			88134,~~073~~666
Total sales		~~731~~246,~~865~~772			~~551~~176,~~732~~761			1,~~191~~438,~~366~~138			~~900~~1,~~551~~077,312
Cost and expenses:
Cost of product		~~519,~~154,379			~~361~~93,~~713~~345			~~820~~975,~~826~~205			~~576~~669,~~228~~573
Cost of installations and service		4640,~~075~~760			4240,~~517~~066			98139,~~697~~457			88128,~~189~~255
(Increase) decrease in the fair value of derivative instruments		~~(13~~16,~~261~~323	)		(42,~~702~~324	)		(2710,~~167~~844	)		(85,~~094~~770	)
Delivery and branch expenses		8153,~~975~~828			6745,~~872~~076			~~147~~201,~~936~~764			~~124~~169,~~694~~770
Depreciation and amortization expenses		4,~~699~~420			34,~~561~~083			913,~~276~~696			711,~~096~~179
General and administrative expenses		5,~~264~~328			5,~~646~~748			1015,~~188~~516			1016,~~699~~447
Operating income		87,959			75,125			131,610			101,739
Operating income (loss)		(28,266	)		(13,881	)		103,344			87,858
Interest expense		(43,~~319~~918	)		(3,~~885~~103	)		(812,~~539~~457	)		(811,~~155~~258	)
Interest income		12,~~241~~018			~~935~~1,421			13,~~773~~791			12,~~329~~750
Amortization of debt issuance costs		(~~732~~618	)		(~~672~~660	)		(12,~~426~~044	)		(1,~~328~~988	)
Loss on redemption of debt		—			~~(1,132~~—	)		(1,700	)		(1,132	)
Income before income taxes		84,149			70,371			121,718			92,453
Income (loss) before income taxes		(30,784	)		(16,223	)		90,934			76,230
Income tax expense		35,468			29,836			52,479			39,913
Income tax expense (benefit)		(12,587	)		(6,232	)		39,892			33,681
Net income	$	48,681		$	40,535		$	69,239		$	52,540
Net income (loss)	$	(18,197	)	$	(9,991	)	$	51,042		$	42,549
General Partner’s interest in net income		236			187			335			241
General Partner’s interest in net income (loss)		(88	)		(47	)		247			194
Limited Partners’ interest in net income	$	48,445		$	40,348		$	68,904		$	52,299
Limited Partners’ interest in net income (loss)	$	(18,109	)	$	(9,944	)	$	50,795		$	42,355
Basic and Diluted income per Limited Partner Unit (1)	$	0.61		$	0.48		$	0.86		$	0.62
Basic and Diluted income (loss) per Limited Partner Unit (1)	$	(0.27	)	$	(0.14	)	$	0.66		$	0.53
Weighted average number of Limited Partner units outstanding:
Basic and Diluted		67,078			7069,~~302~~469			67,078			7170,~~494~~819

(1)	See Note 3 Summary of Significant Accounting Policies - Net Income (Loss) per Limited Partner Unit.

See accompanying notes to condensed consolidated financial statements.

STAR GAS PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL

AND COMPREHENSIVE INCOME

	Number of Units				Common			GeneralPartner			Accum. OtherComprehensiveIncome (Loss)			TotalPartners’Capital
(in thousands)	Common		GeneralPartner
Balance as of September 30, 2010		67,078		326	$	307,092		$	290		$	(27,471	)	$	279,911
Comprehensive income (unaudited):
Net income		—		—		6850,~~904~~795			~~335~~247			—			6951,~~239~~042
Unrealized gain on pension plan obligation		—		—		—			—			12,~~382~~073			12,~~382~~073
Tax effect of unrealized gain on pension plan		—		—		—			—			(~~574~~861	)		(~~574~~861	)
Total comprehensive income		—		—		6850,~~904~~795			~~335~~247			~~808~~1,212			7052,~~047~~254
Distributions		—		—		(1015,~~062~~260	)		(~~100~~159	)		—			(1015,~~162~~419	)
Balance as of March 31, 2011 (unaudited)		67,078		326	$	365,934		$	525		$	(26,663	)	$	339,796
Balance as of June 30, 2011 (unaudited)		67,078		326	$	342,627		$	378		$	(26,259	)	$	316,746

See accompanying notes to condensed consolidated financial statements.

STAR GAS PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

	Six Months EndedMarch 31,
	Nine Months EndedJune 30,
(in thousands - unaudited)	2011			2010
Cash flows provided by (used in) operating activities:
Net income	$	6951,~~239~~042		$	5242,~~540~~549
Adjustment to reconcile net income to net cash provided by (used in) operating activities:
(Increase) decrease in fair value of derivative instruments		(2710,~~167~~844	)		(85,~~094~~770	)
Depreciation and amortization		1015,~~702~~740			813,~~424~~167
Loss on redemption of debt		1,700			1,132
Provision for losses on accounts receivable		710,~~873~~093			56,~~482~~570
Change in deferred taxes		3725,~~858~~464			3530,~~788~~368
Changes in operating assets and liabilities:
Increase in receivables		(~~213~~92,~~123~~107	)		(~~135~~41,~~290~~717	)
Decrease in inventories		276,~~835~~846			21,~~436~~871
(Increase) decrease in other assets		(3,431	)		7,105
Decrease in other assets		6,777			13,624
Increase in accounts payable		6,099			33
Decrease in accounts payable		(2,515	)		(2,622	)
Decrease in customer credit balances		(5245,~~242~~525	)		(5344,~~098~~425	)
Increase in other current and long-term liabilities		31,965			7,494
Increase (decrease) in other current and long-term liabilities		14,255			(500	)
Net cash used in operating activities		(102,692	)		(76,048	)
Net cash provided by (used in) operating activities		(19,074	)		14,247
Cash flows provided by (used in) investing activities:
Capital expenditures		(23,~~721~~838	)		(23,~~664~~581	)
Proceeds from sales of fixed assets		6873			~~155~~220
Acquisitions		(1,791	)		—
Acquisitions (net of cash acquired of $0 and $3,390, respectively)		(6,254	)		(67,703	)
Earnout		—			(123	)
Net cash used in investing activities		(410,~~444~~019	)		(271,~~632~~187	)
Cash flows provided by (used in) financing activities:
Revolving credit facility borrowings		88,416			36,754
Revolving credit facility repayments		(5688,~~823~~416	)		(1736,~~660~~754	)
Repayment of debt		(82,499	)		(50,854	)
Proceeds from the issuance of debt		124,188			—
Debt extinguishment costs		(1,409	)		—
Distributions		(1015,~~162~~419	)		(1015,~~246~~357	)
Unit repurchase		—			(2027,~~771~~928	)
Deferred charges		(36,~~817~~293	)		(130	)
Net cash provided by (used in) financing activities		5718,~~894~~568			(6294,~~907~~269	)
Net decrease in cash and cash equivalents		(4910,~~242~~525	)		(~~141~~151,~~587~~209	)
Cash and cash equivalents at beginning of period		61,062			195,160
Cash and cash equivalents at end of period	$	1150,~~820~~537		$	5343,~~573~~951

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 home heating oil and propane distributor and services provider with one reportable operating segment that principally provides services to residential and commercial customers to heat their homes and buildings. Star Gas Partners is a master limited partnership, which at ~~March~~June 3130, 2011, had outstanding 67.1 million common units (NYSE: “SGU”) representing 99.5% limited partner interest in Star Gas Partners, and 0.3 million general partner units, representing 0.5% general partner interest in Star Gas Partners.

The Partnership is organized as follows:

•

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 is appointed by its sole member, Kestrel Energy Partners, LLC, a Delaware limited liability company (“Kestrel”).

• The Partnership’s operations are conducted through Petro Holdings, Inc. and its subsidiaries (“Petro”). Petro is a Minnesota corporation that is an indirect wholly-owned subsidiary of the Partnership. Petro is a Northeast and Mid-Atlantic region retail distributor of home heating oil and propane that at ~~March~~June 3130, 2011 served approximately ~~408~~407,000 full-service residential and commercial home heating oil and propane customers. Petro also sold home heating oil, gasoline and diesel fuel to approximately 40,000 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 11,000 customers.

•

Star Gas Finance Company is a 100% owned subsidiary of the Partnership. Star Gas Finance Company serves as the co-issuer, jointly and severally with the Partnership, of its $125 million (excluding discount) 8.875% Senior Notes due 2017. The Partnership is dependent on distributions including inter-company interest payments from its subsidiaries to service the Partnership’s debt obligations. The distributions from the Partnership’s subsidiaries are not guaranteed and are subject to certain loan restrictions. Star Gas Finance Company has nominal assets and conducts no business operations. (See Note 6—Long-Term Debt and Bank Facility Borrowings)

2) Common Unit Repurchase and Retirement

On July 19, 2010, the Board of Directors of the Partnership’s General Partner authorized the repurchase of up to 7.0 million of the Partnership’s common units (“Plan II”). 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. In order to facilitate the repurchase program, the Partnership entered into a prearranged unit repurchase plan under Rule 10b5-1 of the Securities Act of 1933, as amended, for up to 4.0 million common units with a third party broker. 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 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.

(in thousands, except per unit amounts)

Period	Total Number of UnitsPurchased as Part of aPublicly AnnouncedPlan or Program		Average PricePaid per Unit (a)		Maximum Number of Unitsthat May Yet Be PurchasedUnder the Plan IIProgram
Plan II - Number of units authorized						7,000
Plan II - Fiscal year 2010 total		1,197	$	4.44		5,803
Plan II - First quarter fiscal year 2011 total		—	$	—		5,803
Plan II - Second quarter fiscal year 2011 total		—	$	—		5,803
Plan II - Third quarter fiscal year 2011 total		—	$	—		5,803

(a)	Amounts include repurchase costs.

3) 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 three and ~~six~~nine month period ended ~~March~~June 3130, 2011 and ~~March~~June 3130, 2010 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 accounting principles generally accepted in the United States 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, 2010.

Use of Estimates

The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates.

Revenue Recognition

Sales of heating oil and other fuels are recognized at the time of delivery of the product to the customer and sales of heating and air conditioning equipment are recognized at the time of installation. Revenue from repairs and maintenance service is recognized upon completion of the service. Payments received from customers for heating oil equipment service contracts are deferred and amortized into income over the terms of the respective service contracts, on a straight-line basis, which generally do not exceed one year. To the extent that the Partnership anticipates that future costs for fulfilling its contractual obligations under its service maintenance contracts will exceed the amount of deferred revenue currently attributable to these contracts, the Partnership recognizes a loss in current period earnings equal to the amount that anticipated future costs exceed related deferred revenues.

Cost of Product

Cost of product includes the cost of heating oil, diesel, propane, kerosene, heavy oil, gasoline, throughput costs, barging costs, option costs, and realized gains/losses on closed derivative positions for product sales.

Cost of Installations and Service

Cost of installations and service includes equipment and material costs, wages and benefits for equipment technicians, dispatchers and other support personnel, subcontractor expenses, commissions and vehicle related costs.

Delivery and Branch Expenses

Delivery and branch expenses include wages and benefits and department related costs for drivers, dispatchers, mechanics, customer service, sales and marketing, compliance, credit and branch accounting, information technology, insurance and operational support.

General and Administrative Expenses

General and administrative expenses include wages and benefits and department related costs for human resources, finance and corporate accounting, administrative support and supply.

Allowance for Doubtful Accounts

The allowance for doubtful accounts, which includes the allowance for long-term receivables, is the Partnership’s best estimate of the amount of trade receivables that may not be collectible. The level of the allowance is based on many quantitative and qualitative factors, including historical loss experience, historical collection patterns, overdue status, delinquency trends, economic conditions and credit risk quality. The Partnership has an established process to periodically review current and past due trade receivable balances to determine the adequacy of the allowance. No single statistic or measurement determines the adequacy of the allowance. Historical trade receivable recoveries and charge-offs are considered as part of this periodical review. Different assumptions or changes in economic conditions could result in changes to the allowance for doubtful accounts.

The allowance is determined at an aggregate level for all trade receivables that are performing in accordance with payment terms and are not materially past due. The Partnership assigns possible loss factors to each trade receivable type aging category to determine its allowance level. The loss factors are determined based on quantitative and qualitative factors, including historical loss experience, trade receivable duration, aging trends, economic conditions and credit risk quality.

The Partnership also reviews its trade receivables for impairment based on delinquencies. These trade receivables consist of materially past due amounts and other trade receivables requiring significant collection efforts including litigation. The Partnership considers the impairment on non-performing trade receivables as a component included in the allowance.

In addition to the calculations discussed above, other qualitative factors are taken into account to arrive at the allowance balance. The total allowance reflects management’s estimate of losses inherent in its trade receivables at the balance sheet date.

Allocation of Net Income (Loss)

Net income (loss) for partners’ capital and statement of operations is allocated to the general partner and the limited partners in accordance with their respective ownership percentages, after giving effect to cash distributions paid to the general partner in excess of its ownership interest, if any.

Net Income (Loss) per Limited Partner Unit

Income per limited partner unit is computed in accordance with FASB ASC 260-10-45-60 Basic and Diluted Earnings per Share topic, Participating Securities and the Two-Class Method subtopic (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 ~~required~~performed, in which the Partnership’s distribution levels are taken into account.

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

Basic and Diluted Earnings Per Limited Partner: (in thousands, except per unit data)	Three Months ~~EndedMarch~~EndedJune 3130,						~~Six~~Nine Months ~~EndedMarch~~EndedJune 3130,
	2011			2010			2011		2010
Net income	$	48,681		$	40,535		$	69,239	$	52,540
Net income (loss)	$	(18,197	)	$	(9,991	)	$	51,042	$	42,549
Less General Partners’ interest in net income		236			187			335		241
Less General Partners’ interest in net income (loss)		(88	)		(47	)		247		194
Net income available to limited partners		48,445			40,348			68,904		52,299
Net income (loss) available to limited partners		(18,109	)		(9,944	)		50,795		42,355
Less dilutive impact of theoretical distribution of earnings under FASB ASC 260-10-45-60		~~7,308~~—			~~6,594~~—			116,~~320~~702		75,~~929~~000
Limited Partner’s interest in net income under FASB ASC 260-10-45-60	$	41,137		$	33,754		$	57,584	$	44,370
Limited Partner’s interest in net income (loss) under FASB ASC 260-10-45-60	$	(18,109	)	$	(9,944	)	$	44,093	$	37,355
Per unit data:
Basic and diluted net income available to limited partners	$	0.72		$	0.57		$	1.03	$	0.73
Basic and diluted net income (loss) available to limited partners	$	(0.27	)	$	(0.14	)	$	0.76	$	0.60
Less dilutive impact of theoretical distribution of earnings under FASB ASC 260-10-45-60		~~0.11~~—			~~0.09~~—			0.1710		0.1107
Limited Partner’s interest in net income under FASB ASC 260-10-45-60	$	0.61		$	0.48		$	0.86	$	0.62
Limited Partner’s interest in net income (loss) under FASB ASC 260-10-45-60	$	(0.27	)	$	(0.14	)	$	0.66	$	0.53
Weighted average number of Limited Partner units outstanding		67,078			7069,~~302~~469			67,078		7170,~~494~~819

Cash Equivalents

The Partnership considers all highly liquid investments with a maturity of three months or less, when purchased, to be cash equivalents.

Inventories

The Partnership’s inventory of heating oil and other fuels are stated at the lower of cost computed on the weighted average cost (WAC) method, or market. All other inventories, representing parts and equipment are stated at the lower of cost computed on the FIFO method, or market.

(in thousands)	~~March~~June 3130,2011		September 30,2010
Heating oil and other fuels	$	2344,~~828~~997	$	51,678
Fuel oil parts and equipment		15,~~388~~394		15,056
	$	3960,~~216~~391	$	66,734

Derivatives and Hedging – Disclosures and Fair Value Measurements

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 and priced purchase commitments.

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 ~~March~~June 3130, 2011, the Partnership had 0.79 million gallons of physical inventory and had 32.41 million gallons of swap contracts to buy heating oil; 85.30 million gallons of call options; 2.90 million gallons of put options and 3642.16 million net gallons of synthetic calls. To hedge the inter-month differentials for our price-protected customers, its physical inventory on hand, and inventory in transit, the Partnership as of ~~March~~June 3130, 2011 had 29 8.40 million gallons of future contracts to buy heating oil; 33 9.63 million gallons of future contracts to sell heating oil; and 312.26 million gallons of swap contracts to sell heating oil. To hedge a portion of its internal fuel usage, the Partnership as of ~~March~~June 3130, 2011, had 01.62 million gallons of swap contracts to buy gasoline; and 0.49 million gallons of swap contracts and 0.52 million gallons of synthetic calls to buy diesel.

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 ~~March~~June 3130, 2010, the Partnership had 0.9 million gallons of physical inventory and had 0.67 million gallons of swap contracts to buy heating oil; 4337.02 million gallons of call options; 0.27 million gallons of put options and 918.23 million net gallons of synthetic calls. To hedge the inter-month differentials for our price-protected customers, its physical inventory on hand, and inventory in transit, the Partnership as of ~~March~~June 3130, 2010 had 2314.02 million gallons of future contracts to buy heating oil; 33 20.68 million gallons of future contracts to sell heating oil; and 1115.37 million gallons of swap contracts to sell heating oil. To hedge a portion of its internal fuel usage, the Partnership as of ~~March~~June 3130, 2010, had 0.69 million gallons of swap contracts to buy gasoline and 1.20 million gallons of swap contracts to buy diesel.

The Partnership’s derivative instruments are with the following counterparties: JPMorgan Chase Bank, N.A., Societe Generale, Cargill, Inc., Key Bank N.A., Bank of America, N.A., Newedge USA, LLC, and Wells Fargo Bank, N.A. The Partnership assesses counterparty credit risk and maintains master netting arrangements with its counterparties to help manage the risks, and records its derivative positions on a net basis. Based on our assessment, the Partnership considers counterparty credit risk to be low. At ~~March~~June 3130, 2011, the aggregate cash posted as collateral in the normal course of business at counterparties was $0.1 million. Positions with counterparties who are also parties to our revolving credit facility are collateralized under that facility. As of ~~March~~June 3130, 2011, $0.1.4 million of hedging losses was secured under the credit facility.

FASB ASC 815-10-05 Derivatives and Hedging topic, established accounting and reporting standards requiring that derivative instruments be recorded at fair value and included in the consolidated balance sheet as assets or liabilities, along with qualitative disclosures regarding the derivative activity. To the extent derivative instruments designated as cash flow hedges are effective and the standard’s documentation requirements have been met, changes in fair value are recognized in other comprehensive income until the underlying hedged item is recognized in earnings. The Partnership has elected not to designate its derivative instruments as hedging instruments under this standard and the change in fair value of the derivative instruments is recognized in our statement of operations in the line item (Increase) decrease in the fair value of derivative instruments. Realized gains and losses are recorded in cost of product.

FASB ASC 820-10 Fair Value Measurements and Disclosures topic, 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. The market prices used to value the Partnership’s derivatives have been determined using the New York Mercantile Exchange (“NYMEX”) and independent third party prices that are reviewed for reasonableness.

~~The~~10 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.

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 HedgingInstrumentsUnder FASB ASC 815-10	Balance Sheet Location	Total			Quoted Prices inActive Markets forIdentical AssetsLevel 1			Significant OtherObservable InputsLevel 2			SignificantUnobservableInputsLevel 3
Derivatives Not Designated as HedgingInstruments Under FASB ASC 815-10	Balance Sheet Location	Total			Quoted Prices inActive Markets forIdentical AssetsLevel 1			Significant OtherObservable InputsLevel 2			SignificantUnobservableInputsLevel 3
Asset Derivatives at March 31, 2011
Asset Derivatives at June 30, 2011
Commodity contracts	Fair asset and fair liability value of derivative instruments	$	4014,~~341~~748		$	131,~~281~~295		$	2713,~~060~~453		$	—
Commodity contracts	Long-term derivative assets ~~netted~~included ~~with~~in ~~long-term~~the ~~derivative~~deferred ~~liabilities,~~charges ~~included~~and in other ~~long-term~~assets, ~~liabilities~~net balance		64—			39—			25—			—
Commodity contract assets at March 31, 2011		$	40,405		$	13,320		$	27,085		$	—
Commodity contract assets at June 30, 2011		$	14,748		$	1,295		$	13,453		$	—
Liability Derivatives at March 31, 2011
Liability Derivatives at June 30, 2011
Commodity contracts	Fair liability and fair asset value of derivative instruments	$	(144,~~077~~442	)	$	(131,~~322~~393	)	$	(~~755~~3,049	)	$	—
Commodity contracts	Long-term derivative liabilities included in other long-term liabilities		~~(220~~—	)		~~(209~~—	)		~~(11~~—	)		—
Commodity contract liabilities at March 31, 2011		$	(14,297	)	$	(13,531	)	$	(766	)	$	—
Commodity contract liabilities at June 30, 2011		$	(4,442	)	$	(1,393	)	$	(3,049	)	$	—
Asset Derivatives at September 30, 2010
Commodity contracts	Fair asset and fair liability value of derivative instruments	$	11,991		$	29		$	11,962		$	—
Commodity contracts	Long-term derivative assets included in the deferred charges and other assets, net balance		43			—			43			—
Commodity contract assets at September 30, 2010		$	12,034		$	29		$	12,005		$	—
Liability Derivatives at September 30, 2010
Commodity contracts	Fair liability and fair asset value of derivative instruments	$	(6,419	)	$	(101	)	$	(6,318	)	$	—
Commodity contract liabilities at September 30, 2010		$	(6,419	)	$	(101	)	$	(6,318	)	$	—

(In thousands)

The Effect of Derivative Instruments on the Statement of Operations

Amount of (Gain) or Loss Recognized

Amount of (Gain) or Loss Recognized in Income onDerivative

Derivatives Not Designatedas Hedging InstrumentsUnder FASB ASC 815-10

Location of (Gain) or LossRecognized in Income onDerivative

Three ~~MonthsEnded~~MonthsEndedJune ~~March 31~~30,2011

Three ~~MonthsEnded~~MonthsEndedJune ~~March 31~~30,2010

~~Six~~Nine ~~MonthsEnded~~MonthsEndedJune ~~March 31~~30,2011

~~Six~~Nine ~~MonthsEnded~~MonthsEndedJune ~~March 31~~30,2010

Commodity contracts

Cost of product (a)

(59,~~870~~717

)

111,~~618~~373

4(5,~~205~~512

)

2123,~~877~~251

Commodity contracts

Cost of installations and service (a)

(~~321~~384

)

(~~297~~289

)

(~~414~~798

)

(~~518~~807

)

Commodity contracts

Delivery and branch expenses (a)

(~~380~~229

)

(~~195~~83

)

(~~483~~712

)

(~~355~~439

)

Commodity contracts

(Increase) / decrease in the fair value of derivative instruments

~~(13~~16,~~261~~323

)

(42,~~702~~324

)

(2710,~~167~~844

)

(85,~~094~~770

)

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

1211

Weather Hedge Contract

Weather hedge contract is recorded in accordance with the intrinsic value method defined by FASB ASC 815-45-15 Derivatives and Hedging topic, Weather Derivatives subtopic (EITF 99-2). The premium paid is amortized over the life of the contract and the intrinsic value method is applied at each interim period.

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)	~~March~~June 3130,2011		September 30,2010
Property and equipment	$	~~149~~151,~~498~~196	$	146,494
Less: accumulated depreciation		~~105~~106,~~005~~721		101,782
Property and equipment, net	$	44,~~493~~475	$	44,712

Business Combinations

The Partnership uses the acquisition method of accounting in accordance with FASB ASC 805 Business Combinations. The acquisition method of accounting requires the Partnership to use significant estimates and assumptions, including fair value estimates, as of the business combination date, and to refine those estimates as necessary during the measurement period (defined as the period, not to exceed one year, in which the amounts recognized for a business combination may be adjusted). Each acquired company’s operating results are included in the Partnership’s consolidated financial statements starting on the date of acquisition. The purchase price is equivalent to the fair value of consideration transferred. Tangible and identifiable intangible assets acquired and liabilities assumed as of the date of acquisition, are recorded at the acquisition date fair value. The separately identifiable intangible assets generally are comprised of customer lists, trade names and covenants not to compete. Goodwill is recognized for the excess of the purchase price over the net fair value of assets acquired and liabilities assumed.

Costs that are incurred to complete the business combination such as investment banking, legal and other professional fees are not considered part of consideration transferred, and are charged to general and administrative expense as they are incurred. For any given acquisition, certain contingent consideration may be identified. Estimates of the fair value of liability or asset classified contingent consideration are included under the acquisition method as part of the assets acquired or liabilities assumed. At each reporting date, these estimates are remeasured to fair value, with changes recognized in earnings.

Goodwill and Intangible Assets

Goodwill and intangible assets include goodwill, customer lists, trade names and covenants not to compete.

Goodwill is the excess of cost over the fair value of net assets in the acquisition of a company. Under FASB ASC 350-10-05 Intangibles-Goodwill and Other, a potential goodwill impairment is deemed to exist if the net book value of a reporting unit exceeds its estimated fair value. If goodwill of a reporting unit is determined to be impaired, the amount of impairment is measured based on the excess of the net book value of the goodwill over the implied fair value of the goodwill.

The Partnership has selected August 31 of each year to perform its annual impairment review under this standard. The evaluations utilize an Income Approach and Market Approach (consisting of the Market Comparable and the Market Transaction Approach), which contain reasonable and supportable assumptions and projections reflecting management’s best estimate in deriving the Partnership’s total enterprise value. The Income Approach calculates over a discrete period the free cash flow generated by the Partnership to determine the enterprise value. The Market Comparable approach compares the Partnership to comparable companies in similar industries to determine the enterprise value. The Market Transaction approach uses exchange prices in actual sales and purchases of comparable businesses to determine the enterprise value.

The total enterprise value as indicated by these two approaches is compared to the Partnership’s book value of net assets and reviewed in light of the Partnership’s market capitalization.

Customer lists are the names and addresses of an acquired company’s customers. Based on historical retention experience, these lists are amortized on a straight-line basis over seven to ten years.

experience, these lists are amortized on a straight-line basis over seven to ten years.

Trade names are the names of acquired companies. Based on the economic benefit expected and historical retention experience of customers, trade names are amortized on a straight-line basis over seven to twenty years.

Covenants not to compete are agreements with the owners of acquired companies and are amortized over the respective lives of the covenants on a straight-line basis, which are generally five years.

Partners’ Capital

Comprehensive income includes net income, plus certain other items that are recorded directly to partners’ capital. Accumulated other comprehensive income reported on the Partnerships’ consolidated balance sheets consists of unrealized gains/losses on pension plan obligations and the tax affect. For the three months ended ~~March~~June 3130, 2011, comprehensive ~~income~~loss was $49(17.18) million, comprised of net ~~income~~loss of $48(18.72) million, an unrealized gain on pension plan obligation of $0.7 million and the tax effect of $(0.3) million. For the three months ended ~~March~~June 3130, 2010, comprehensive ~~income~~loss was $~~40.~~(9.6) million, comprised of net ~~income~~loss of $40(10.50) million, an unrealized gain on pension plan obligation of $0.6 million and the tax affect of $(0.2) million.

For the ~~six~~nine months ended ~~March~~June 3130, 2011, comprehensive income was $7052.03 million, comprised of net income of $6951.20 million, an unrealized gain on pension plan obligation of $12.41 million and the tax effect of $(0.68) million. For the ~~six~~nine months ended ~~March~~June 3130, 2010, comprehensive income was $5343.36 million, comprised of net income of $5242.65 million, an unrealized gain on pension plan obligation of $1.28 million and the tax affect of $(0.5 7) million.

Income Taxes

The Partnership is a master limited partnership and is not subject to tax at the entity level for Federal and state income tax purposes. Rather, income and losses of the Partnership are allocated directly to the individual partners. While the Partnership will generate non-qualifying Master Limited Partnership revenue in its corporate subsidiaries, distributions from the corporate subsidiaries to the Partnership are generally included in the determination of qualified Master Limited Partnership income. All or a portion of the distributions received by the Partnership from the corporate subsidiaries could be taxable as a dividend or capital gain to the partners.

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

As most of the Partnership’s income is derived from its corporate subsidiaries, these financial statements reflect significant Federal and state income taxes. For corporate subsidiaries of the Partnership, a consolidated Federal income tax return is filed. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amount of assets and liabilities and their respective tax bases and operating loss carry-forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled.

The current and deferred income tax expenses for the three and ~~six~~nine months ended ~~March~~June 3130, 2011, and 2010 are as follows:

	Three Months EndedMarch 31,						Six Months EndedMarch 31,
	Three Months EndedJune 30,						Nine Months EndedJune 30,
(in thousands)	2011			2010			2011		2010
Income before income taxes	$	84,149		$	70,371		$	121,718	$	92,453
Income (loss) before income taxes	$	(30,784	)	$	(16,223	)	$	90,934	$	76,230
Current tax expense	$	12,590		$	3,277		$	14,621	$	4,126
Current tax expense (benefit)	$	(194	)	$	(810	)	$	14,427	$	3,316
Deferred tax expense		22,878			26,559			37,858		35,787
Deferred tax expense (benefit)		(12,393	)		(5,422	)		25,465		30,365
Total tax expense	$	35,468		$	29,836		$	52,479	$	39,913
Total tax expense (benefit)	$	(12,587	)	$	(6,232	)	$	39,892	$	33,681

As of the calendar tax year ended December 31, 2010, Star Acquisitions, a wholly-owned subsidiary of the Partnership, had an estimated Federal net operating loss carry forward (“NOL”) of approximately $16.4 million. ofThe Federal NOLs, which ~~$7.3~~will ~~million~~expire isbetween ~~related~~2018 and 2024, are generally available to ~~the~~offset ~~acquisition~~any offuture ~~Champion~~taxable ~~Energy~~income ~~Corporation.~~but are ~~The~~also ~~Federal~~subject ~~NOLs,~~to ~~which~~annual ~~will~~limitations ~~expire between~~on ~~2018~~the ~~and~~amount ~~2024,~~that can be used.

are generally available to offset any future taxable income but are also subject to annual limitations on the amount that can be used.

FASB ASC 740-10-05-6 Income Taxes topic, Uncertain Tax Position subtopic (SFAS No. 109 and FIN 48), provides financial statement accounting guidance for uncertainty in income taxes and tax positions taken or expected to be taken in a tax return.

At ~~March~~ June 3130, 2011, we had unrecognized income tax benefits totaling $2.45 million including related accrued interest and penalties of $0.34 million. These unrecognized tax benefits are primarily the result of Federal tax uncertainties. If recognized, these tax benefits and related interest and penalties would be recorded as a benefit to the effective tax rate.

We believe that the total liability for unrecognized tax benefits will decrease by $0.01 million during the next 12 months ending ~~March~~June 3130, 2012. Our continuing practice is to recognize interest and penalties 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, five, 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.

Sales, Use and Value Added Taxes

Taxes are assessed by various governmental authorities on many different types of transactions. Sales reported for product, installation and service exclude taxes.

Recent Accounting Pronouncements

In May 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2011-04, Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. generally accepted accounting principles (“U.S. GAAP”) and the International Financial Reporting Standards (“IFRS”), that results in a consistent definition of fair value and common requirements for measurement of and disclosure about fair value. The new guidance clarifies and changes some fair value measurement principles and disclosure requirements under U.S. GAAP. Among them is the clarification that the concepts of highest and best use and valuation premise in a fair value measurement, should only be applied when measuring the fair value of nonfinancial assets. Additionally, the new guidance requires quantitative information about unobservable inputs, and disclosure of the valuation processes used and narrative descriptions with regard to fair value measurements within the Level 3 categorization of the fair value hierarchy. The new guidance is effective for interim and annual reporting periods beginning after December 15, 2011, with early adoption prohibited. The adoption of this new guidance is not expected to have a material impact on the Partnership’s Consolidated Financial Statements.

In June 2011, the FASB issued ASU No. 2011-05, Comprehensive Income (Topic 220): Presentation of Comprehensive Income. This standard eliminates the option to present items of other comprehensive income (“OCI”) as part of the statement of changes in stockholders’ equity, and instead requires either OCI presentation and net income in a single continuous statement to the statement of operations, or as a separate statement of comprehensive income. ASU No. 2011-05 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011, with early adoption permitted. The Partnership is required to adopt this update in the first quarter of fiscal year 2013. The adoption of ASU No. 2011-05 will not impact our results of operations or the amount of assets and liabilities reported.

4) Goodwill and Intangibles, net

Goodwill

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

Balance as of September 30, 2010	$	199,052
Fiscal year 2011 activity		(~~207~~99	) (a)
Balance as of March 31, 2011	$	198,845
Balance as of June 30, 2011	$	198,953

(a) As provided for by FASB ASC 805 Accounting for Business Combinations and Noncontrolling Interests, ~~the~~ the Partnership refined the fleet valuation of its May 10, 2010 Champion acquisition within the measurement period, resulting in a reduction of the goodwill acquired from $16,110 to $15,900. The balance of the change in goodwill reflects the business acquisition activity as of ~~March~~June 3130, 2011.

The Partnership performed its annual goodwill impairment valuation for the period ending August 31, 2010 and determined that there was no goodwill impairment. The preparation of this analysis (see Note 3. Summary of Significant Accounting Policies – Goodwill and Intangible Assets) was based upon management’s estimates and assumptions, and future impairment calculations would be affected by actual results that are materially different from projected amounts. To provide for a sensitivity of the discount rates and transaction multiples used, ranges of high and low values are employed in the analysis, with the low values examined to ensure that a reasonably likely change in an assumption would not cause the Partnership to reach a different conclusion.

Intangibles, net

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


	June 30, 2011						September 30, 2010
(in thousands)	Gross Carrying Amount		Accum. Amortization		Net		Gross Carrying Amount		Accum. Amortization		Net
Customer lists and other intangibles	$	255,250	$	201,545	$	53,705	$	252,385	$	193,491	$	58,894

Amortization expense for intangible assets was $8.1 million for the nine months ended June 30, 2011 compared to $6.7 million for the nine months ended June 30, 2010. Total estimated annual amortization expense related to intangible assets subject to amortization, for the fiscal year ending September 30, 2011 and the four succeeding fiscal years ending September 30, is as follows (in thousands):

	March 31, 2011						September 30, 2010
	Estimated Annual BookAmortization Expense
(in thousands)	GrossCarryingAmount		Accum.Amortization		Net		GrossCarryingAmount		Accum.Amortization		Net
2011	$	10,344
Customer lists and other intangibles	$	252,778	$	198,957	$	53,821	$	252,385	$	193,491	$	58,894
2012	$	6,132
2013	$	6,130
2014	$	6,055
2015	$	5,919

Amortization expense for intangible assets was $5.5 million for the six months ended March 31, 2011 compared to $4.1 million for the six months ended March 31, 2010. Total estimated annual amortization expense related to intangible assets subject to amortization, for the fiscal year ending September 30, 2011 and the four succeeding fiscal years ending September 30, is as follows (in thousands):

	Estimated Annual BookAmortization Expense
2011	$	10,264
2012	$	5,914
2013	$	5,912
2014	$	5,837
2015	$	5,701

5) Business Combinations

OnDuring ~~December 16, 2010~~ the ~~Partnership~~nine ~~acquired~~months aended ~~heating oil and propane dealer for $1.6 million in cash, and on February~~June 930, 2011, the Partnership acquired athree heating oil ~~dealer~~and propane dealers for an aggregate $06.23 million in cash. The operating results of these ~~two~~three acquisitions have been included in the Partnership’s consolidated financial statements since the date of acquisition, and are not material to the Partnership’s financial condition, results of operations, or cash flows. Preliminary fair values of the assets acquired and liabilities assumed are comprised primarily of intangibles, and certain working capital items, ~~and~~which are reflected in the Consolidated Balance Sheet as of ~~March~~June 3130, 2011, and are pending final valuation within the permitted measurement period.

6) Long-Term Debt and Bank Facility Borrowings

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

	At March 31, 2011				At September 30, 2010
	At June 30, 2011				At September 30, 2010
	CarryingAmount		EstimatedFair Value (a)		CarryingAmount		EstimatedFair Value (a)
8.875% Senior Notes (b)	$	124,~~219~~241	$	~~128~~130,~~750~~156	$	—	$	—
10.25% Senior Notes (c)		—		—		82,770		83,908
Revolving Credit Facility Borrowings (d)		~~31,593~~—		~~31,593~~—		—		—
Total debt	$	~~155~~124,~~812~~241	$	~~160~~130,~~343~~156	$	82,770	$	83,908
Total long-term portion of debt	$	124,~~219~~241	$	~~128~~130,~~750~~156	$	82,770	$	83,908

(a)

The Partnership’s fair value estimates of long-term debt are made at a specific point in time, based on relevant market information, open market quotations and information about the financial instrument. These estimates are subjective in nature and involve uncertainties and matters of significant judgment. Changes in assumptions could significantly affect the estimates.

(b) The Partnership issued $125.0 million (excluding discount) 8.875% Senior Notes in November 2010 in a private placement offering pursuant to Rule 144A and Regulation S under the Securities Act of 1933, as amended (the “Private Notes”). In February 2011, the Partnership concluded an exchange of all the Private Notes for substantially identical public notes registered with the Securities and Exchange Commission (the “Exchange Notes”). These 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 included above was $0.8 million at ~~March~~June 3130, 2011. Under the terms of the indenture, these notes permit restricted payments ofafter ~~$22~~passing ~~million,~~certain ~~permit~~financial ~~the~~tests. The Partnership tocan incur debt up to $100 million for acquisitions ~~without~~and ~~passing~~can ~~certain~~also ~~financial~~pay ~~tests,~~restricted ~~and~~payments ~~restrict the proceeds~~ of ~~asset~~$22.0 ~~sales~~million ~~from~~without ~~being~~passing ~~invested~~certain infinancial ~~current assets for purposes of the “asset sale” covenant~~tests.

(c)	In December 2010, the Partnership redeemed its 10.25% Senior Notes due February 2013, at a price equal to 101.708% of face value plus any accrued and unpaid interest. The Partnership reported a $1.7 million loss on this redemption.

(d)

In June 2011, the Partnership entered into an amended and restated asset based revolving credit facility agreement with a bank syndication comprised of fifteen banks. This amended and restated facility expires in June 2016, provides the Partnership with the ability to borrow up to $250 million ($300 million during the heating season from December to April 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. The Partnership can increase the facility size by $100 million without the consent of the bank group. 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 (as appointed in the credit agreement), which shall not be unreasonably withheld. Obligations under the revolving 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 is LIBOR plus (i) 1.75% (if availability, as defined in the revolving credit facility 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 0.375% per annum. This amended and restated revolving credit facility imposes certain restrictions, 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.

The Partnership is obligated to meet certain financial covenants under the amended and restated revolving credit facility, including the requirement to maintain at all times either excess availability (borrowing base less amounts borrowed and letters of credit issued) of 12.5% of the revolving commitment then in effect or a fixed charge coverage ratio (as defined in the credit agreement) of not less than 1.1. In addition, the Partnership must maintain excess availability of at least $52.5 million (17.5% of the revolving commitment then in effect) and a fixed charge coverage ratio of 1.15 in order to make any distributions to unitholders. Certain activities including investments, acquisitions, asset sales, inter-company dividends or distributions cannot be made (including those needed to pay interest or principle on the 8.875% senior notes), except to the Partnership or a wholly owned subsidiary of the Partnership, if the relevant covenant described above has not been met. The occurrence of an event of default or an acceleration under the amended and restated revolving credit facility would result in the Partnership’s inability to obtain further borrowings under that facility, which could adversely affect its results of operations. Such a default may also restrict the ability of the Partnership to obtain funds from its subsidiaries in order to pay interest or paydown debt. An acceleration under the amended and restated revolving credit facility would result in a default under the Partnership’s other funded debt.

At June 30, 2011, no amount was outstanding under the revolving credit facility and $46.7 million of letters of credit were issued. No amount was outstanding under the revolving credit facility at September 30, 2010, and $42.3 million of letters of credit were issued.

~~(d)~~As ~~In July 2009, the Partnership entered into an amended and restated asset based revolving credit facility agreement with a bank syndication comprised~~ of ~~nine banks. This amended facility~~June 30, ~~that extends to July 2012~~2011, provides the Partnership with the ability to borrow up to $240 million ($290 million during the heating season from November to April 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 which reduce availability ~~under~~was ~~this facility. The Partnership can increase the facility size by~~ $~~50 million without the consent of the bank group~~155.9 ~~The bank group is not obligated to fund the $50~~ million, ~~increase.~~and If the ~~bank group elects not to fund the increase, the~~ Partnership ~~can~~was ~~add~~in compliance ~~additional lenders to the group,~~ with the ~~consent~~fixed ofcharge ~~the~~coverage ~~Agent, which shall not be unreasonably withheld~~ratio. ~~The~~As ~~interest~~of ~~rate is LIBOR plus (i) 3.50% (if availability~~September 30, ~~as defined in the revolving credit facility agreement is greater than or equal to $150 million)~~2010, ~~or (ii) 3.75% (if~~ availability iswas ~~greater than~~ $75104.8 million ~~but less than $150 million)~~, orand ~~(iii)~~the ~~4.00%~~Partnership ~~(if~~was ~~availability~~in iscompliance ~~less~~with ~~than or equal to $75 million). The commitment fee on~~ the ~~unused~~fixed ~~portion~~charge ofcoverage ~~the facility is 0~~ratio.~~75%~~ ~~per annum.~~

InOn ~~January~~June 30, ~~2010~~2011, the Partnership ~~entered~~filed ~~into~~ a ~~first~~registration ~~amendment~~statement toon Form S-3 with the ~~amended~~Securities and ~~restated~~Exchange ~~asset~~Commission, ~~based~~utilizing a ~~revolving~~shelf ~~credit~~registration ~~facility agreement~~process ~~that~~or ~~updated~~continuous offering process. Under this shelf registration process, the ~~consolidated~~Partnership ~~fixed~~may, ~~charges~~from ~~defined~~time ~~term~~to time, sell up to $250 million in one or more offerings, 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.

At March 31, 2011, $31.6 million was outstanding under the revolving credit facility and $46.7 million of letters of credit were issued. No amount was outstanding under the revolving credit facility at September 30, 2010, and $42.3 million of letters of credit were issued.

Obligations under the revolving credit facility are secured by liens on substantially all assets and are guaranteed by the Partnership. The revolving credit facility imposes certain restrictions on the Partnership, including restrictions on its ability to incur additional indebtedness, to pay distributions to its unitholders, to pay inter-company dividends or distributions, make investments, grant liens, sell assets, make acquisitions and engage in certain other activities. The revolving credit facility also requires the Partnership to maintain certain financial ratios, and contains borrowing conditions and customary events of default, including nonpayment of principal or interest, violation of covenants, inaccuracy of representations and warranties, cross-defaults to other indebtedness, bankruptcy and other insolvency events. The occurrence of an event of default or an acceleration under the revolving credit facility would result in the Partnership’s inability to obtain further borrowings under that facility, which could adversely affect its results of operations. Such a default may also restrict the ability of the Partnership to obtain funds from its subsidiaries in order to pay interest or paydown debt. An acceleration under the revolving credit facility would result in a default under the Partnership’s other funded debt.

Under the terms of the revolving credit facility, the Partnership must maintain at all times either availability (borrowing base less amounts borrowed and letters of credit issued) of $43.5 million or a fixed charge coverage ratio (as defined in the credit agreement) of not less than 1.10x. In addition, the Partnership must maintain availability of at least $40 million and a fixed charge coverage ratio for the trailing twelve months of 1.15x in order to make its minimum quarterly distributions of $0.0675 per unit, and 1.25x to make any distributions in excess of the minimum quarterly distributions. No inter-company dividends or distributions can be made (including those needed to pay interest or principle on the 8.875% Senior Notes) if the relevant covenant described above has not been met.

As of March 31, 2011, availability was $181.5 million, and the Partnership was in compliance with the fixed charge coverage ratio. As of September 30, 2010, availability was $104.8 million, and the Partnership was in compliance with the fixed charge coverage ratio.

7) Employee Pension Plan

	Three Months EndedMarch 31,						Six Months EndedMarch 31,
	Three Months EndedJune 30,						Nine Months EndedJune 30,
(in thousands)	2011			2010			2011			2010
Components of net periodic benefit cost:
Service cost	$	—		$	—		$	—		$	—
Interest cost		748			812			12,~~496~~244			12,~~623~~435
Expected return on plan assets		(879	)		(~~667~~666	)		(12,~~758~~637	)		(1,~~332~~998	)
Net amortization		691			616			12,~~382~~073			1,~~232~~848
Net periodic benefit cost	$	560		$	~~761~~762		$	1,~~120~~680		$	12,~~523~~285

For the ~~six~~nine months ended ~~March~~June 3130, 2011, the Partnership contributed $1.29 million and expects to ~~make~~ make an additional $2.1.4 million contribution in fiscal 2011 to fund its pension obligation.

8) Supplemental Disclosure of Cash Flow Information

	Six Months EndedMarch 31,
	Nine Months EndedJune 30,
(in thousands)	2011		2010
Cash paid during the period for:
Income taxes, net	$	25,~~263~~897	$	~~641~~1,478
Interest	$	512,~~130~~420	$	89,~~697~~690
Debt redemption premium	$	1,409	$	854
Non-cash financing activities:
Increase (decrease) in interest expense—amortization of net debt premium 10.25% and debt discount 8.875%	$	930	$	(74104	)
Decrease in net debt premium attributable to redemption of debt	$	247	$	203

9) Commitments and Contingencies

The Partnership’s operations are subject to all operating hazards and risks normally incidental to handling, storing and transporting and otherwise providing for use by consumers of combustible liquids such as home heating oil and propane. As a result, at any given time the Partnership is a defendant in various legal proceedings and litigation arising in the ordinary course of business. The Partnership maintains insurance policies with insurers 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. 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.

10) Subsequent Events

Quarterly Distribution Declared

On ~~April~~July 14, 2011, the Partnership declared a quarterly distribution of $0.0775 per common unit, payable on ~~May~~August 1312, 2011, to holders of record on ~~May~~August 54, 2011.

1817

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 home heating oil and propane, 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 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, 2010 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 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 the historical financial condition and results of our operations and should be read in conjunction with the description of our business in Item 1. “Business” of the Form ~~10K~~10-K 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 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 of each fiscal year, 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.~~

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 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 month or a year was warmer or cooler than usual. Degree days are officially observed by the National Weather Service and officially archived by the National Climatic Data Center. For purposes of evaluating our results of operations, we use the normal heating degree day amount as reported by the National Weather Service in our operating areas.

Impact on Operating Results of Increasing Wholesale Product Costs

During the heating season of fiscal 2011, wholesale product costs ~~continued to escalate~~increased significantly, which limited ~~Star’s~~our ability to maintain and/or expand margins for variable and ceiling priced customers. Conversely, during certain peak months of the heating seasons for fiscal 2010 and 2009, wholesale product costs declined, which contributed to ~~the~~our ~~Partnership’s~~ ability to expand ~~its~~our per gallon margins during these periods, as wholesale prices decreased more rapidly than our retail prices. For example, over 90% of our ceiling ~~customer~~customers reached their maximum contract price during the three months ended March 31, 2011, as compared to the three months ended March 31, 2010, when 70% of our ceiling customers reached their maximum contract price. During the three months ended March 31, 2009, less than 1% of our ceiling customers reached their maximum contract price. If wholesale product costs continue to ~~escalate~~increase, the Partnership’s ability to maintain and/or expand per gallon margins could be greatly diminished and profitability measures would be adversely impacted. As retail prices continue to rise, gross customer losses could increase and ~~Star’s~~our ability to attract new customers might decrease, which could result in an increase in net customer attrition. The ~~recent~~2011 increase in the cost of home heating oil and petroleum products in general has also resulted in an increase in certain operating expenses that are directly tied to the underlying cost of product such as bad debt expense, credit card processing costs, vehicle fuels and other transportation expenses. InFor fiscal 2011, the Partnership has increased its reserve rate for doubtful accounts when compared to fiscal 2010 in response to an increase in the days sales outstanding for accounts receivable, greater consumption due to colder temperatures and higher selling prices. As of July 29, 2011, home heating oil costs were $0.36 per gallon higher than the average for the nine months ended June 2011. Going forward, the impact of this additional increase will be reflected in future operating costs. In addition, interest expense may rise further as the Partnership is required to finance a higher level of accounts receivable and inventory.

Home Heating Oil Price Volatility

In recent years, the wholesale price of home heating oil has been extremely volatile, resulting in increased consumer price sensitivity to heating costs and increased gross customer attrition. 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 ~~fiscal 2011, 2010, 2009, and 2008 by quarter, is illustrated by the following chart:~~

	Fiscal 2011				Fiscal 2010				Fiscal 2009				Fiscal 2008
Quarter Ended	Low		High		Low		High		Low		High		Low		High
December 31	$	2.19	$	2.54	$	1.78	$	2.12	$	1.20	$	2.85	$	2.16	$	2.71
March 31		2.49		3.09		1.89		2.20		1.13		1.63		2.42		3.15
June 30 (a)		3.13		3.32		1.87		2.35		1.31		1.86		2.88		3.97
September 30						1.92		2.24		1.50		1.96		2.72		4.11

(a)Table toof April 30, 2011 Contents

fiscal 2011, 2010, 2009, and 2008 by quarter, is illustrated by the following chart:


	Fiscal 2011				Fiscal 2010				Fiscal 2009				Fiscal 2008
Quarter Ended	Low		High		Low		High		Low		High		Low		High
December 31	$	2.19	$	2.54	$	1.78	$	2.12	$	1.20	$	2.85	$	2.16	$	2.71
March 31		2.49		3.09		1.89		2.20		1.13		1.63		2.42		3.15
June 30		2.75		3.32		1.87		2.35		1.31		1.86		2.88		3.97
September 30 (a)		2.93		3.13		1.92		2.24		1.50		1.96		2.72		4.11

(a) to July 29, 2011

Impact on Liquidity of Wholesale Product Cost Volatility

~~The wholesale price of home heating oil has been extremely volatile over the last several years.~~ Our liquidity is adversely impacted in times of increasing heating oil prices, as we must use 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 heating oil prices due to the increased margin requirements for futures contracts and collateral requirements for swaps that we use to manage market risks related to our fixed price customers and physical inventory that are not immediately offset by lower inventory and accounts receivable carrying costs.

Impact of Warm Weather on Operating Results; Weather Hedge Contract

Weather conditions have a significant impact on the demand for home heating oil and propane because our customers depend on these products principally for heating purposes. Actual weather conditions can vary substantially from year to year, significantly affecting our financial performance. To partially mitigate the adverse effect of warm weather on our cash flows, we have used weather ~~insurance~~ ~~and weather~~ hedging contracts for a number of years. For the fiscal ~~2011~~ 2012 heating season, we have entered into a weather hedge contract with Renaissance Trading Ltd. under which we ~~were~~are entitled to receive a payment of $35,000 per heating degree-day, when the total number of heating degree-days in the period covered ~~was~~ is less than 92.5% of the 10-year average. The hedge ~~covered~~covers the period from November 1, ~~2010~~2011 through March 31, ~~2011~~2012 taken as a whole, and ~~had~~has a maximum payout of $12.5 million. The heating degree days during this period exceeded 92.5% of the 10 year average so no payments were due under this contract. The Partnership will evaluate purchasing a similar contract for fiscal 2012.

Per Gallon Gross Profit Margins

We believe the change in 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 and propane volume is sold to individual customers under an arrangement pre-establishing a ceiling sales price or fixed price for home heating oil and propane over a fixed period of time (generally 12 months). When these price-protected customers agree to purchase home heating oil and propane 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 and propane 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 could 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 losses could be greater.~~

month be less than the hedged volume, our hedging losses could be greater.

Derivatives

FASB ASC 815-10-05 Derivatives and Hedging topic, established accounting and reporting standards requiring 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 standard, 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 standard, and, as a result, the changes in fair value of the derivative instruments are recognized in our statement of operations. Therefore, we experience great 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 home heating oil and propane 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.

Income Taxes—Net Operating Loss Carry Forward

At December 31, 2006, we had Federal NOLs of $160.8 million and at December 31, 2010, we estimate that our Federal NOLs were $16.4 million, ~~(including $7.3 million of NOLs that were acquired with the Champion acquisition)~~ and most are subject to annual limitations on the amount that can be used. Over this four year period, we utilized $37.9 million of Federal NOLs on average each year to offset our taxable income. We expect that ~~over~~during ~~the~~calendar ~~next~~year ~~twelve~~2011 ~~months~~ we will utilize substantially all of the remaining unlimited Federal NOLs. After we exhaust the Federal NOLs, the amount of cash taxes that we will pay will increase significantly and will reduce the annual amount of cash available for distribution to unitholders. For example, in calendar 2007, 2008, 2009 and 2010 we paid or expect to pay Federal cash taxes of $1.0 million, $0.6 million, $0.7 million and $0.8 million respectively. If we did not have the Federal NOLs available to us, our Federal cash taxes would have increased to $17.2 million, $11.1 million, $9.9 million and $14.7 million for calendar 2007, 2008, 2009 and 2010 respectively.

Income Taxes—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 subsidiaries will 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. Our subsidiaries file their tax returns based on a calendar year. The amounts below are based on our September 30, fiscal year.

Estimated Depreciation and Amortization Expense

Fiscal Year	Book		Tax
2011	$	20,~~349~~069	$	3130,~~532~~487
2012		14,~~214~~003		28,~~285~~451
2013		1112,~~151~~695		2426,~~899~~096
2014		911,~~918~~382		2022,~~887~~272
2015		910,~~027~~390		1719,~~895~~250

2122

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

Currently, our main asset and source of income is our 100% ownership interest in Star Acquisitions, Inc. (“Star Acquisitions”), which is the parent company of Petro Holdings, Inc. Our unitholders do not receive any of the tax benefits normally associated with owning units in a publicly traded partnership, as any cash coming from Star Acquisitions to us will generally have been taxed first at a corporate level and then may also be taxable to our unitholders as dividends, reported via annual Forms K-1. The production of the Forms K-1 themselves is an expensive and administratively intensive process. Thus, we have all the administrative issues and costs associated with being a large, publicly traded partnership, but our unitholders do not currently receive any material tax benefits from this structure.

To reduce these administrative expenses and to better rationalize our tax reporting structure we are considering making an election sometime in the future to be treated as a corporation for Federal and State income tax purposes. While we would still remain a publicly traded partnership for legal and governance purposes, for income tax purposes our unitholders would be treated as owning stock in a corporation rather than being partners in a partnership. Subsequent to the year of election unitholders would receive Forms 1099-DIV annually for any dividends and would no longer receive Form K-1. In the year of election unitholders would receive both, each form covering part of the year.

While there could be negative income tax consequences to our unitholders with this election, we intend to only make this election if we believe that it will have no overall material adverse impact on our unitholders, of which there can be no assurance. Since determining this is a function of projecting taxable earnings, making assumptions regarding the payment of distributions, and trying to determine when, during any particular calendar year, making the election will have the least impact on the most number of unitholders, when or, even if, we will make this election is not determinable at this time. Unitholders are encouraged to consult their tax advisors with respect to these possible outcomes.

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 business, 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:

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.

Acquisitions

During the first ~~six~~nine months of fiscal 2011, the Partnership completed ~~two~~three acquisitions and added approximately 16,~~900~~700 home heating oil and propane accounts. During fiscal 2010, the Partnership completed five acquisitions and added approximately 56,100 home heating oil, propane and security accounts. While the ~~these~~2010 ~~later~~ acquisitions provided additional ~~revenues~~revenue in fiscal 2010, the Partnership’s profitability measures such as operating income and net income were adversely impacted by such acquisitions as the associated product costs and operating expenses of the 2010 acquisitions exceeded revenues, reflecting the fact that such acquisitions were all completed after the end of the fiscal 2010 heating season. We expect that the fiscal 2010 ~~and 2011~~ acquisitions should positively impact our profitability measures in fiscal 2011 when compared to fiscal 2010.

Customer Attrition

We measure net customer attrition for our full service residential and commercial home heating oil and propane customers. (Starting October 1, 2010, we have included propane customers in this calculation as several of our recent acquisitions included propane operations.) Net customer attrition is the difference between gross customer losses and customers added through marketing efforts. Customers purchased through acquisitions are not counted as gross customer gains. However the impact of marketing activity on acquired operations from the date that the acquisitions took place is included in the results below. Gross customer losses are the result of a number of factors, including price competition, move-outs, service issues, 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~~24 ~~Customer Gains, Gross Customer Losses and Net Customer Attrition:~~

	Fiscal Year Ended
	2011							2010 (a)							2009 (a)
	Gross Customer				NetAttrition			Gross Customer				NetAttrition			Gross Customer				NetAttrition
	Gains		Losses					Gains		Losses					Gains		Losses
First Quarter		21,900		24,100		(2,200	)		19,000		21,600		(2,600	)		26,300		31,800		(5,500	)
Second Quarter		11,700		17,100		(5,400	)		11,000		14,200		(3,200	)		11,700		24,100		(12,400	)
		33,600		41,200		(7,600	)		30,000		35,800		(5,800	)		38,000		55,900		(17,900	)

Gross ~~Customer~~customer ~~Gains,~~gains ~~Gross Customer Losses~~ and ~~Net~~gross ~~Customer~~customer ~~Attrition~~losses ~~as a Percentage of the Customer Base:~~

	Fiscal Year Ended
	2011									2010 (a)									2009 (a)
	Gross Customer						NetAttrition			Gross Customer						NetAttrition			Gross Customer						NetAttrition
	Gains			Losses						Gains			Losses						Gains			Losses
First Quarter		~~5.3~~21,900	%		~~5.8~~24,100	%		(~~0.5~~2,200	%)		~~5.1~~19,000	%		~~5.8~~21,600	%		(~~0.7~~2,600	%)		~~6.5~~26,300	%		~~7.9~~31,800	%		(~~1.4~~5,500	%)
Second Quarter		~~2.8~~11,800	%		~~4.1~~17,200	%		(~~1.3~~5,400	%)		~~3.0~~11,000	%		~~3.8~~14,200	%		(~~0.8~~3,200	%)		~~2.9~~11,700	%		~~6.0~~24,100	%		(~~3.1~~12,400	%)
		8.1	%		9.9	%		(1.8	%)		8.1	%		9.6	%		(1.5	%)		9.4	%		13.9	%		(4.5	%)
Third Quarter		6,000			11,400			(5,400	)		5,300			12,600			(7,300	)		5,900			12,300			(6,400	)
Total		39,700			52,700			(13,000	)		35,300			48,400			(13,100	)		43,900			68,200			(24,300	)

Net customer attrition as a percentage of the home heating oil customer base.


	Fiscal Year Ended
	2011									2010 (a)									2009 (a)
	Gross Customer						Net Attrition			Gross Customer						Net Attrition			Gross Customer						Net Attrition
	Gains			Losses			Net Attrition			Gains			Losses			Net Attrition			Gains			Losses			Net Attrition
First Quarter		5.3	%		5.8	%		(0.5	%)		5.1	%		5.8	%		(0.7	%)		6.5	%		7.9	%		(1.4	%)
Second Quarter		2.8	%		4.1	%		(1.3	%)		3.0	%		3.8	%		(0.8	%)		2.9	%		6.0	%		(3.1	%)
Third Quarter		1.5	%		2.8	%		(1.3	%)		1.4	%		3.3	%		(1.9	%)		1.5	%		3.1	%		(1.6	%)

Total		9.6	%		12.7	%		(3.1	%)		9.5	%		12.9	%		(3.4	%)		10.9	%		17.0	%		(6.1	%)

(a)	Prior to October 1, 2010, we measured only home heating oil net customer attrition.

During the first ~~six~~nine months of fiscal 2011, we lost 713,~~600~~000 accounts (net), or 13.81% of our home heating oil and propane customer base, as compared to ~~our~~a loss of 513,~~800~~100 accounts (net), or 13.54% of our home heating oil customer base during the first ~~six~~nine months of fiscal 2010. The increase in the absolute number of gross customer losses of 54,~~400~~300 accounts was largely due to losses associated with ~~increases~~higher ~~in the price of~~ home heating oil prices.

Net of attrition, the Partnership’s beginning customer base for the above calculations increased by approximately 10.9% from the beginning of fiscal 2010 to the beginning of fiscal 2011 due to acquisitions and the inclusion of our propane accounts in the customer base. For the ~~six~~nine months ended ~~March~~June 3130, 2011, gross gains and gross losses increased by 12.05% and 158.19%, respectively, as compared to the prior year period, due inlargely ~~part~~ to the 10.9% increase in size of the Partnership’s customer base.

During the ~~six~~nine months ended ~~March~~June 3130, 2011, we lost 01.70% of our accounts to natural gas which compares to losses to natural gas of 0.69% for the ~~six~~nine months ended ~~March~~June 3130, 2010. While this increase is modest, we believe that conversions to natural gas could increase as natural gas has become significantly less expensive than home heating oil on an equivalent BTU basis.

2325

Price-Protected Customer Renewals

Approximately 7276% of the Partnership’s price-protected customers have agreements with us that are subject to annual renewal in the period from April through November of each fiscal year. If a significant number of these customers elect not to renew their price-protected agreements with us and do not continue as our customers under a variable price-plan, the Partnership’s near term profitability, liquidity and cash flow will be adversely impacted. As of ~~April~~July 29, 2011, the wholesale cost of home heating oil as measured by the NYMEX was $3.2610 and approximately $01.9705 higher than at ~~April~~July 30, 2010. Based on these recent prices, our price-protected customers will be offered renewal contracts at significantly higher prices than last year which may adversely impact the acceptance rate of these renewals.

Results of Operations

The following is a discussion of the 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.

2426

Three Months Ended ~~March~~June 3130, 2011

Compared to the Three Months Ended ~~March~~June 3130, 2010

Volume

For the three months ended ~~March~~June 3130, 2011, retail volume of home heating oil and propane increased by 219.2 million gallons, or 1326.52%, to ~~178~~44.93 million gallons, as compared to ~~157~~35.71 million gallons for the three months ended ~~March~~June 3130, 2010. AnFor this non-heating season period, 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, is found below:

(in millions of gallons)	Heating Oiland ~~Propane~~propane
Volume - Three months ended March 31, 2010		157.7
Volume - Three Months Ended June 30, 2010		35.1
Acquisitions		223.19
Impact of colder temperatures		12.9
Impact of Colder Temperatures		5.5
Net customer attrition		(8.4	)
Residential Customer Attrition - Net		(1.3	)
Lower Margin COD/BID and Commercial Volume		(10.36	)
Conservation and Other		(4.1	)
Other		1.7
Change		219.2
Volume - Three months ended March 31, 2011		178.9
Volume - Three Months Ended June 31, 2011		44.3

For those locations that the Partnership operated in both periods, which we sometimes refer to in this report as our “base business” (i.e., excluding acquisitions), temperatures in our geographic areas of operations for the three months ended ~~March~~June 3130, 2011 were 824.71% colder than the three months ended ~~March~~June 3130, 2010 and approximately 116.4% ~~colder~~warmer than normal, as reported by the National Oceanic Atmospheric Administration (“NOAA”). Between ~~April~~July 1, 2010 and ~~March~~June 3130, 2011, net customer attrition was 5.40%, and the above table reflects the lost volume related to this net customer attrition. Due to the significant increase in the price per gallon of the products ~~that~~ we sell over the last several years, we believe that customers ~~were~~have been using less oil given similar temperatures when compared to prior periods. We believe that this conservation trend will continue. In addition, the downturn in the economy has impacted demand for commercial end-users of home heating oil and other petroleum products.

Volume of other petroleum products for the three months ended ~~March~~June 3130, 2011 increased by 30.27 million gallons, or ~~30.~~8.6%, to 138.8 million gallons, as compared to 108.51 million gallons of other petroleum products sold during the three months ended ~~March~~June 3130, 2010. This increase was largely due to the additional volume provided from acquisitions.

The percentage of heating oil volume sold to residential variable price customers increased to 4442.1% for the three months ended ~~March~~June 3130, 2011, as compared to 4241.69% for the three months ended ~~March~~June 3130, 2010. The percentage of heating oil volume sold to residential price-protected customers ~~decreased~~increased to 4345.53% for the three months ended ~~March~~June 3130, 2011, as ~~compared~~ compared to 4443.28% for the three months ended ~~March~~June 3130, 2010. For the three months ended ~~March~~June 3130, 2011, sales to commercial/industrial customers decreased to 12.45% of total heating oil volume sales, as compared to 1314.23% for the three months ended ~~March~~ June 3130, 2010. Generally, the shift to variable pricing was largely due to our customers’ reluctance to “lock in” or “cap” their prices, as home heating oil and propane prices for our price-protected offerings were higher during the peak renewal season preceding fiscal 2011 than during the comparable renewal period preceding fiscal 2010.

Product Sales

For the three months ended ~~March~~June 3130, 2011, product sales increased $~~175~~68.83 million, or 3452.45%, to $~~686~~198.5 million, as compared to $~~510~~130.72 million for the three months ended ~~March~~June 3130, 2010, due to the previously described ~~increases~~increase in ~~sales~~ volume ~~of 14.6%~~ and higher product selling prices in response to an increase in wholesale product cost.

Installation and Service Sales

For the three months ended ~~March~~June 3130, 2011, service and installation sales increased $41.47 million, or 103.7%, to $4548.4 3 million, as compared to $4146.06 million for the three months ended ~~March~~June 3130, 2010, largely due to additional revenue from acquisitions of $52.04 million. For our base business, installation revenue declined by $0.82 million, or 51.83%, and service sales declined by $0.5 million, ~~largely~~or 1.6%, due in part to net customer attrition for the base business. We believe that the expiration in December 2010 of certain federal income tax incentives for consumers adversely impacted our installation sales during the third quarter of fiscal 2011 when compared to the prior-year period.

decline in the customer base. We believe that the recent expiration of certain federal income tax incentives for consumers will adversely impact our installation sales over the remainder of fiscal 2011.

Cost of Product

For the three months ended ~~March~~June 3130, 2011, cost of product increased $~~157~~61.51 million, or 4365.54%, to $~~519~~154.24 million, as compared to $~~361~~93.73 million for the three months ended ~~March~~June 3130, 2010, due to ~~increases~~increase in volume ~~sales~~ of 1422.68% and higher per gallon product costs of 2534.37%.

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 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 ~~March~~June 3130, 2011 decreased by $0.~~0122~~0390 per gallon, or 14.30%, to $0.~~9177~~9424 per gallon, from $0.~~9299~~9814 per gallon in the three months ended ~~March~~June 3130, 2010. ~~Our~~When ~~fiscal~~compared ~~2010~~to ~~and~~the ~~fiscal~~home ~~2011~~heating ~~acquisitions~~oil ~~have~~and apropane ~~different~~margins ~~per~~realized ~~gallon~~for ~~gross~~the ~~profit~~three ~~margin~~months ~~profile~~ended ~~and~~June 30, ~~operating~~2009, ~~cost structure than~~ our ~~base~~ ~~business. Generally, the~~ per gallon margins are ~~from~~up ~~our recent acquisitions have been lower than the base business~~5.0% ~~Excluding~~or ~~acquisitions, home heating oil and propane margins declined~~ $0.~~0036~~0447 per gallon~~, or 0~~.~~4%.~~ Product sales and cost of product include home heating oil, ~~and~~ propane, ~~and~~ other petroleum products, and liquidated damage billings.

~~During~~The ~~the~~Partnership ~~heating~~utilizes ~~season~~weighted ofaverage ~~fiscal~~costing ~~2011,~~to ~~home heating~~value ~~oil~~its ~~costs~~inventory ~~continued~~of tohome ~~escalate,~~heating ~~which~~oil ~~limited~~and ~~margin expansion capability~~propane. ~~Conversely,~~During ~~during~~ the ~~heating~~three ~~season~~months ofended ~~fiscal~~June 30, ~~2010~~2011, ~~home~~a ~~heating~~period ~~oil~~in ~~product costs declined,~~ which ~~contributed~~prices torose ~~the~~and ~~Partnership’s~~accounts ~~ability~~for less tothan ~~expand~~15 % ~~its~~of ~~home heating~~our ~~oil~~annual ~~margins~~volume ~~that year~~sales, asthe ~~wholesale~~Partnership ~~prices~~increased ~~decreased~~its ~~more~~physical ~~rapidly~~inventory ~~than~~of ~~our~~home ~~retail~~heating ~~prices~~oil from 6.7 million ~~Over~~gallons ~~90%~~to of13.8 million ~~our~~gallons. ~~ceiling~~We ~~customer~~estimate ~~reached~~that ~~their~~the ~~maximum~~per ~~contract~~gallon ~~price~~margins ~~during~~for the three months ended ~~March~~ June 3130, 2011 aswere lower by $ 0.0352 cents per gallon when compared to the three months ended ~~March~~June 3130, 2010 ~~when~~due ~~70%~~to ofweighted ~~our~~average ~~ceiling~~costing ~~customers~~and ~~reached~~the ~~their~~increase ~~maximum~~in ~~contract~~our ~~price~~physical inventory. IfThe ~~the~~Partnership ~~wholesale~~hedges ~~product~~its ~~costs~~physical ~~continues~~inventory toand ~~escalate~~at June 30, ~~our~~2011 ~~ability~~had toan ~~maintain~~unrealized ~~and/~~gain of $1.6 million or ~~expand~~$ 0.0352 per gallon ~~margins~~of ~~would~~home beheating ~~greatly~~oil ~~diminished~~ and ~~our profitability~~propane ~~measures~~sold ~~would~~during bethe ~~adversely~~three ~~impacted~~months ended June 30, 2011.

26During the heating season of fiscal 2011 and continuing through the third quarter of fiscal 2011, home heating oil costs rose, which limited margin expansion capability. Conversely, during the heating season of fiscal 2010, home heating oil product costs declined, which contributed to the Partnership’s

	Three Months Ended
	March 31, 2011				March 31, 2010
	Amount(000)		PerGallon		Amount(000)		Per Gallon
Home Heating Oil and Propane
Volume (in millions of gallons)		178,914				157,670
Sales	$	643,723	$	3.5979	$	485,898	$	3.0817
Cost		479,535		2.6803		339,284		2.1519
Gross Profit	$	164,188	$	0.9177	$	146,614	$	0.9299
	Amount(000)		PerGallon		Amount(000)		Per Gallon
Other Petroleum Products
Volume (in millions of gallons)		13,782				10,540
Sales	$	42,729	$	3.1003	$	24,815	$	2.3544
Cost		39,619		2.8747		22,429		2.1280
Gross Profit	$	3,110	$	0.2256	$	2,386	$	0.2264
	Amount(000)				Amount(000)		Change
Total Product
Sales	$	686,452			$	510,713	$	175,739
Cost		519,154				361,713		157,441
Gross Profit	$	167,298			$	149,000	$	18,298

ability to expand its home heating oil margins that year, as wholesale prices decreased more rapidly than our retail prices. During the third quarter of fiscal 2011, home heating oil and propane costs increased by $0.1639 per gallon, while during the third quarter of fiscal 2010 home heating oil and propane costs decreased by $0.0027 per gallon. If wholesale product costs continue to escalate, our ability to maintain and/or expand per gallon margins would be greatly diminished and our profitability measures would be adversely impacted.

For the three months ended March 31, 2011, total product gross profit increased by $18.3 million to $167.3 million, as compared to $149.0 million for the three months ended March 31, 2010, due to the impact of higher home heating oil and propane volume ($19.8 million), and the additional gross profit from other petroleum products sold ($0.7 million), which was reduced by slightly lower home heating oil and propane margins ($2.2 million).


	Three Months Ended
	June 30, 2011				June 30, 2010
	Amount (000)		Per Gallon		Amount (000)		Per Gallon
Home Heating Oil and Propane
Volume (in millions of gallons)		44,270				35,145

Sales	$	167,634	$	3.7866	$	110,026	$	3.1306
Cost		125,913		2.8442		75,534		2.1492

Gross Profit	$	41,721	$	0.9424	$	34,492	$	0.9814


	Amount (000)		Per Gallon		Amount (000)		Per Gallon
Other Petroleum Products
Volume (in millions of gallons)		8,779				8,054

Sales	$	30,816	$	3.5103	$	20,142	$	2.5007
Cost		28,466		3.2426		17,811		2.2115

Gross Profit	$	2,350	$	0.2677	$	2,331	$	0.2892


	Amount (000)				Amount (000)		Change
Total Product
Sales	$	198,450			$	130,168	$	68,282
Cost		154,379				93,345		(61,034	)

Gross Profit	$	44,071			$	36,823	$	7,248

For the three months ended June 30, 2011, total product gross profit increased by $7.2 million to $44.1 million, as compared to $36.8 million for the three months ended June 30, 2010, as the impact of higher home heating oil and propane volume ($8.9 million), was reduced by lower home heating oil and propane margins ($1.7 million).

(Increase) Decrease in the Fair Value of Derivative Instruments

During the three months ended ~~March~~June 3130, 2011, the ~~increase~~decrease in the fair value of derivative instruments since March 31, 2011 resulted in the recording of a $1316.3 million net ~~credit~~charge due to the expiration of certain hedged positions orand their realization to cost of product (a $59.53 million charge), and ana ~~increase~~decrease in the market value for unexpired hedges (a $187.~~8 million~~0 ~~credit~~million charge).

During the three months ended ~~March~~June 3130, 2010, the ~~increase~~decrease in the fair value of derivative instruments since March 31, 2010 resulted in the recording of a $42.73 million net ~~credit~~charge due to the expiration of certain hedged positions orand their realization to cost of product (a $41.82 million credit) and a decrease in the market value for unexpired hedges (a $03.15 million charge).

~~Cost~~29 ~~of Installations and Service~~

During the three months ended March 31, 2011, cost of installations and service increased $3.6 million, or 8.4%, to $46.1 million, as compared to $42.5 million for the three months ended March 31, 2010, as an estimated $4.5 million of additional costs associated with acquisitions was only slightly reduced by a $0.9 million decline in installation and service costs in our base business. Management views the service and installation department on a combined basis because many expenses cannot be separated or allocated to either service or installation billings. Many administrative functions and direct expenses such as service technician time cannot be precisely allocated and generally remain in service costs.

Installation costs increased by $1.2 million to $12.5 million, or 90.0% of installation sales, during the three months ended March 31, 2011, versus $11.3 million, or 87.0% of installation sales during the three months ended March 31, 2010. The increase in installation costs was largely due to acquisitions ($1.5 million). Service expenses increased by $2.4 million to $33.6 million, or 106.5% of service sales, during the three months ended March 31, 2011, from $31.3 million in the three months ended March 31, 2010, or 111.4% of sales. The increase in service costs was again largely due to acquisitions ($3.0 million). For the three months ended March 31, 2011, a combined loss from service and installation of $0.7 million was generated, compared to a combined loss of $1.5 million for the three months ended March 31, 2010.

Cost of Installations and Service

During the three months ended June 30, 2011, cost of installations and service increased $0.7 million, or 1.7%, to $40.8 million, as compared to $40.1 million for the three months ended June 30, 2010, as an estimated $2.1 million of additional costs associated with acquisitions was reduced by a $1.4 million decline in installation and service costs in our base business. Management views the service and installation department on a combined basis because many expenses cannot be separated or allocated to either service or installation billings. Many administrative functions and direct expenses such as service technician time cannot be precisely allocated and generally remain in service costs.

Installation costs increased by $0.3 million to $13.8 million, or 84.4% of installation sales, during the three months ended June 30, 2011, versus $13.5 million, or 85.6% of installation sales during the three months ended June 30, 2010. The increase in installation costs was largely due to acquisitions ($0.7 million). Service expenses increased by $0.3 million to $26.9 million, or 84.3% of service sales, during the three months ended June 30, 2011, from $26.6 million in the three months ended June 30, 2010, or 86.2% of sales. The increase in service costs was again largely due to acquisitions ($1.4 million). For the three months ended June 30, 2011, a combined gross profit from service and installation of $7.6 million was generated, compared to a combined gross profit of $6.5 million for the three months ended June 30, 2010.

Delivery and Branch Expenses

For the three months ended ~~March~~June 3130, 2011, delivery and branch expenses increased $148.17 million, or 2019.84%, to $8253.08 million, compared to $6745.91 million for the three months ended ~~March~~June 3130, 2010. Acquisitions added $8.3.5 million in delivery and branch expense. In the base business, delivery and branch expenses increased by $5.82 million largely due to higher delivery costs of $10.8 5 million associated with the increase in volume and ~~numerous snow storms experienced in the second quarter of fiscal 2011,~~ higher bad debt expense and credit card processing fees of $1.95 million due to the increase in sales offor ~~32.6%~~both the three and nine months ended June 30, 2011. The Partnership has increased its reserve rate for doubtful accounts for the three months ended June 30, 2011, when compared to the three months ended June 30, 2010 in response to an increase in the days sales outstanding for accounts receivable, greater ~~insurance~~consumption ~~claims~~due ~~expense~~to colder temperatures and higher selling prices. Depending upon collections during the fourth quarter of fiscal 2011, this reserve rate will be adjusted accordingly. Insurance expense rose by $23.0 million due to an increase in ~~part~~reserves tofor prior year claims and higher current year claim costs resulting from the extreme winter ~~weather~~ ~~conditions~~weather.

Depreciation and Amortization

For the three months ended ~~March~~June 3130, 2011, depreciation and amortization ~~expenses~~expense increased by $10.13 million, or 328.03%, to $4.74 million, as compared to $34.61 million for the three months ended ~~March~~ June 3130, 2010.

Depreciation expense was higher by $0.53 million due primarily to additional depreciation expense from depreciable property and equipment of ~~fiscal~~recent ~~2010~~ acquisitions. Amortization expense was ~~higher~~unchanged ~~by $0.6 million~~ as the additional amortization expense from fiscal 2010 and 2011 acquisitions of $10.18 million was ~~somewhat~~ reduced by a decline in amortization expense attributable to fiscal 2003 and fiscal 2000 acquisitions with either a 7 or 10 year life that became fully amortized.

General and Administrative Expenses

For the three months ended ~~March~~ June 3130, 2011, general and administrative expenses decreased $0.34 million to $5.3 million, from $5.6 million for the three months ended March 31, 2010, primarily due to lower professional fees and lower pension expense relating to the Partnership’s frozen defined benefit pension plan.

~~Operating Income~~30 ~~(Loss)~~

ForTable the three months ended March 31, 2011, operating income increased $12.8 million to $87.9 million, from $75.1 million for the three months ended March 31, 2010, as an increase in product gross profit of $18.3 million, an improvement in net service and installation of $0.8 million, and a favorable change in the fair value of derivative instruments of $8.6 million was reduced by higher operating expense increases (including depreciation and amortization) of $14.9 million. Contents

million to $5.3 million, from $5.7 million for the three months ended June 30, 2010, primarily due to lower acquisition related expenses.

Operating Loss

For the three months ended June 30, 2011, the operating loss increased $14.4 million to $28.3 million, from $13.9 million for the three months ended June 30, 2010, as an increase in product gross profit of $7.2 million and an improvement in net service and installation of $1.0 million, was reduced by an unfavorable change in the fair value of derivative instruments of $14.0 million and by higher operating expenses (including depreciation and amortization) of $8.6 million.

Interest Expense

For the three months ended ~~March~~June 3130, 2011, interest expense increased by $0.48 million, or 1126.23% to $4.3.9 million as compared to $3.9 1 million for the three months ended ~~March~~June 3130, 2010. In November 2010, the Partnership issued $125.0 million of 8.875% Senior Notes due 2017 and repaid $82.5 million of 10.25% Senior Notes due 2013. While average long-term debt outstanding increased by $1542.15 million, the weighted average long-term borrowing rate declined by 1.4% to 8.875% from 10.25% and, as a result, the aggregate interest expense on ~~the~~ our long-term debt ~~was~~increased ~~largely~~by ~~unchanged~~$0.7 million.

During the three months ended ~~March~~ June 3130, 2011, the Partnership borrowed on average $564.86 million under its bank credit facility or $470.6 million ~~more~~less than the three months ended ~~March~~June 3130, 2010, which resulted in an increase in interest expense of $0.5 million. The impact of the increase in amounts borrowed under the bank credit facility was mitigated by a decline in the weighted average interest rate from 5.7% to 4.3%.

Interest Income

For the three months ended ~~March~~June 3130, 2011, interest income increased $0.36 million, or 3242.78%, to $1.2.0 million, as compared to $01.9 4 million for the three months ended ~~March~~June 3130, 2010, due to higher finance charge income from acquisitions and an overall increase in the amount of past due accounts receivable.

Amortization of Debt Issuance Costs

For the three months ended ~~March~~June 3130, 2011, amortization of debt issuance costs was unchanged at $0.76 million, when compared to the three months ended ~~March~~June 3130, 2010.

28Income Tax Benefit

For the three months ended June 30, 2011, the Partnership’s income tax benefit increased $6.4 million, to $12.6 million, from $6.2 million for the three months ended June 30, 2010. The increase in income tax benefit was mainly due to the higher pretax losses of $14.6 million.

Net Loss

For the three months ended June 30, 2011, the Partnership generated a net loss of $18.2 million, compared to a net loss of $10.0 million for the three months ended June 30, 2010, as the operating loss increase of $14.4 million was partially offset by an increase in income tax benefit of $6.4 million.

Loss on Redemption of Debt

During the three months ended March 31, 2010, the Partnership repurchased $50.0 million face value of its 10.25% Senior Notes due February 2013, at an average price of $101.7 per $100 of principal plus accrued interest. The Partnership recorded a loss of $1.1 million. The Partnership did not repurchase any Senior Notes during the three months ended March 31, 2011.

Income Tax Expense

For the three months ended March 31, 2011 income tax expense increased $5.7 million, to $35.5 million, from $29.8 million for the three months ended March 31, 2010. The increase in income tax expense was mainly due to the higher pretax income of $13.8 million. The current portion of income tax expense was $12.6 million or 15.0% of pretax income.

Net Income

For the three months ended March 31, 2011, the Partnership generated net income of $48.7 million, compared to $40.5 million for the three months ended March 31, 2010, as the increase in operating income of $12.8 million was partially offset by an increase in income tax expense of $5.7 million.

Adjusted EBITDA

For the three months ended ~~March~~June 3130, 2011, ~~Adjusted EBITDA increased by $5.4 million, or 7.3%, to $79.4 million as~~ the ~~impact~~Adjusted ofEBITDA ~~colder~~loss ~~temperatures~~was ofunchanged ~~8.7%~~at ~~and~~ $~~11.~~7.5 million ofwhen ~~Adjusted~~compared ~~EBITDA~~to ~~provided~~the bythree ~~fiscal~~months ~~2010~~ended ~~and 2011 acquisitions was somewhat offset by net customer attrition in the base business~~June 30, ~~higher~~2010 ~~delivery~~as ~~and branch expenses attributable largely to~~ the ~~numerous~~impact ~~snowstorms~~of incolder ~~our marketing areas~~temperatures, an improvement ~~increase~~ in ~~bad~~service ~~debt~~profitability ~~expense~~ and ~~credit~~the ~~card~~additional ~~processing~~Adjusted ~~fees~~EBITDA ~~due~~from toacquisitions ~~the~~of ~~increase~~$0.5 inmillion ~~sales~~was ~~driven~~offset ~~largely~~ by ~~the~~lower ~~increase~~per ~~in wholesale~~gallon ~~product~~home ~~cost~~heating oil and anpropane ~~increase~~margins inand ~~insurance~~higher ~~claims~~expenses ~~expense due~~ in ~~part~~our tobase ~~the severe winter weather~~business.

	Three Months EndedMarch 31,
	Three Months EndedJune 30,
(in thousands)	2011			2010
Net income	$	48,681		$	40,535
Net loss	$	(18,197	)	$	(9,991	)
Plus:
Income tax expense		35,468			29,836
Income tax benefit		(12,587	)		(6,232	)
Amortization of debt issuance cost		~~732~~618			~~672~~660
Interest expense, net		31,~~078~~900			21,~~950~~682
Depreciation and amortization		4,~~699~~420			34,~~561~~083
EBITDA from continuing operations		92(23,~~658~~846	)		77(9,~~554~~798	)
(Increase) / decrease in the fair value of derivative instruments		~~(13~~16,~~261~~323	)		(42,~~702~~324	)
Loss on redemption of debt		—			1,132
Adjusted EBITDA		(7,523	)		(7,474	)
Adjusted EBITDA		79,397			73,984
Add / (subtract)
Income tax expense		(35,468	)		(29,836	)
Income tax benefit		12,587			6,232
Interest expense, net		(31,~~078~~900	)		(21,~~950~~682	)
Provision for losses on accounts receivable		52,~~225~~220			31,~~334~~088
Increase in accounts receivables		(97,962	)		(58,338	)
Decrease in accounts receivables		121,016			93,573
Decrease in inventories		38,159			11,823
Increase in inventories		(20,989	)		(565	)
Decrease in customer credit balances		(29,108	)		(31,308	)
Increase in customer credit balances		6,717			8,673
Change in deferred taxes		22(12,~~878~~394	)		26(5,~~306~~420	)
Change in other operating assets and liabilities		5(16,~~975~~116	)		3(4,~~924~~130	)
Net cash used in operating activities	$	(13,982	)	$	(3,061	)
Net cash provided by operating activities	$	83,618		$	90,295
Net cash used in investing activities	$	(15,~~262~~575	)	$	(168,~~077~~555	)
Net cash provided by (used in) financing activities	$	13,260		$	(40,960	)
Net cash used in financing activities	$	(39,326	)	$	(31,362	)

EBITDA and Adjusted EBITDA (non-GAAP financial measures)

•

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.

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;

•

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.

3034

~~Six~~Nine Months Ended ~~March~~June 3130, 2011

Compared to the ~~Six~~Nine Months Ended ~~March~~June 3130, 2010

Volume

For the ~~six~~nine months ended ~~March~~June 3130, 2011, retail volume of home heating oil and propane increased by 3747.90 million gallons, or 1516.03%, to ~~291~~335.68 million gallons, as compared to ~~253~~288.78 million gallons for the ~~six~~nine months ended ~~March~~June 3130, 2010. 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, is found below:

(in millions of gallons)	Heating Oiland ~~Propane~~propane
Volume - Six months ended March 31, 2010		253.7
Volume - Nine Months Ended June 30, 2010		288.8
Acquisitions		3539.32
Impact of colder temperatures		18.1
Impact of Colder Temperatures		23.4
Net customer attrition		(13.5	)
Residential Customer Attrition - Net		(11.7	)
Lower Margin COD / BID and Commercial Volume		(14.84	)
Conservation and Other		(0.2	)
Other		0.5
Change		3747.90
Volume - Six months ended March 31, 2011		291.6
Volume - Nine Months Ended June 30, 2011		335.8

Temperatures in our base business geographic areas of operations for the ~~six~~nine months ended ~~March~~June 3130, 2011 were 78.6% colder than the ~~six~~nine months ended ~~March~~June 3130, 2010 and approximately 10.84% ~~colder~~warmer than normal, as reported by the National Oceanic Atmospheric Administration (“NOAA”). Between ~~April~~July 1, 2010 and ~~March~~June 3130, 2011, net customer attrition ~~(excluding acquisitions)~~ was 5.40%, and the above table reflects the lost volume related to this net customer attrition. Due to the significant increase in the price per gallon of the products that we sell over the last several years, we believe that customers are using less given similar temperatures when compared to prior periods. We believe that this conservation trend will continue.

Volume of other petroleum products for the ~~six~~nine months ended ~~March~~June 3130, 2011 increased by 5.6.3 million gallons, or 2822.16%, to 2534.31 million gallons, as compared to 1927.8 million gallons of other petroleum products sold during the ~~six~~nine months ended ~~March~~June 3130, 2010. This increase was largely due to the additional volume provided from acquisitions.

The percentage of heating oil volume sold to residential variable price customers increased to 4443.18% for the ~~six~~nine months ended ~~March~~June 3130, 2011, as compared to 42.1% for the ~~six~~nine months ended ~~March~~June 3130, 2010. The percentage of heating oil volume sold to residential price-protected customers decreased to 43.36% for the ~~six~~nine months ended ~~March~~June 3130, 2011, as compared to 44.32% for the ~~six~~nine months ended ~~March~~June 3130, 2010. For the ~~six~~nine months ended ~~March~~June 3130, 2011, sales to commercial/industrial customers decreased to 12.6% of total heating oil volume sales, as compared to 13.67% for the ~~six~~nine months ended ~~March~~June 3130, 2010. ~~Generally,~~We believe that the shift to variable pricing was ~~largely~~ largely due to our customers’ reluctance to “lock in” or “cap” their prices, as home heating oil and propane prices for our price protected offerings were higher during the peak renewal season preceding fiscal 2011 than during the comparable renewal period preceding fiscal 2010.

Product Sales

For the ~~six~~nine months ended ~~March~~June 3130, 2011, product sales increased $~~278~~347.92 million, or 3436.38%, to $1.129 billion, as compared to $~~812~~942.5 6 million for the ~~six~~nine months ended ~~March~~June 3130, 2010, due to the previously described increases in ~~sales~~ volume ~~of 15.9%~~ and higher product selling prices in response to an increase in wholesale product cost.

Installation and Service Sales

For the ~~six~~nine months ended ~~March~~June 3130, 2011, service and installation sales increased $1113.86 million, or 1310.51%, to $99148.93 million, as compared to $88134.17 million for the ~~six~~nine months ended ~~March~~June 3130, 2010, ~~largely~~ ~~due~~reflecting ~~the~~ additional revenue from acquisitions of $1113.15 million. ~~We believe that the recent expiration of certain federal income tax incentives will adversely impact our installation sales over the remainder of fiscal 2011.~~

Cost of Product

For the ~~six~~nine months ended ~~March~~June 3130, 2011, cost of product increased $~~244~~305.6 million, or 4245.46%, to $~~820~~975.82 million, as compared to $~~576~~669.2 6 million for the ~~six~~nine months ended ~~March~~June 3130, 2010, due to increases in the volume ~~sales~~ of home heating oil and propane and other petroleum products ofsold ~~15.9%~~ and higher per gallon product costs ~~of 22~~.~~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 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 ~~six~~nine months ended ~~March~~June 3130, 2011 decreased by $0.~~0047~~0086 per gallon, or 0.59%, to $0.~~9080~~9125 per gallon, from $0.~~9127~~9211 per gallon in the ~~six~~nine months ended ~~March~~June 3130, 2010. Our fiscal 2010 and fiscal 2011 acquisitions have typically had a different per gallon gross profit margin profile and operating cost structure than our base business. Generally, the per gallon margins from our recent acquisitions have been lower than the base business. Excluding acquisitions, home heating oil and propane margins rose by just $0.~~0043~~0006 per gallon, or 0.~~005~~1% versus the prior-year period. Product sales and cost of product include home heating oil, ~~and~~ propane, ~~and~~ other petroleum products., and liquidated damage billings.

During the heating season of fiscal 2011, wholesale product costs continued to escalate, which limited margin expansion capability. Conversely, during the heating season of fiscal 2010, wholesale product costs declined, which largely contributed to the Partnership’s ability to expand its home heating oil and propane margins during this period, as wholesale prices decreased more rapidly than our retail prices. If wholesale product costs continue to escalate, our ability to maintain and/or expand margins is greatly diminished and our profitability measures would be adversely impacted.

	Six Months Ended
	March 31, 2011				March 31, 2010
	Amount(000)		PerGallon		Amount(000)		Per Gallon
Home Heating Oil and Propane
Volume (in millions of gallons)		291,578				253,654
Sales	$	1,017,521	$	3.4897	$	766,716	$	3.0227
Cost		752,782		2.5818		535,200		2.1100
Gross Profit	$	264,739	$	0.9080	$	231,516	$	0.9127
	Amount(000)		PerGallon		Amount(000)		Per Gallon
Other Petroleum Products
Volume (in millions of gallons)		25,313				19,763
Sales	$	73,899	$	2.9194	$	45,762	$	2.3155
Cost		68,044	$	2.6881		41,028		2.0760
Gross Profit	$	5,855	$	0.2313	$	4,734	$	0.2396
	Amount(000)				Amount(000)		Change
Total Product
Sales	$	1,091,420			$	812,478	$	278,942
Cost		820,826				576,228		244,598
Gross Profit	$	270,594			$	236,250	$	34,344

For the six months ended March 31, 2011, total product gross profit increased by $34.3 million to $270.6 million, as compared to $236.3 million for the six months ended March 31, 2010, due to the impact of higher home heating oil and propane volume ($34.6 million), and the additional gross profit from other petroleum products sold ($1.1 million) somewhat offset by slightly lower home heating oil and propane margins ($1.4 million).


	Nine Months Ended
	June 30, 2011				June 30, 2010
	Amount (000)		Per Gallon		Amount (000)		Per Gallon
Home Heating Oil and Propane
Volume (in millions of gallons)		335,848				288,800

Sales	$	1,185,155	$	3.5288	$	876,742	$	3.0358
Cost		878,695		2.6163		610,734		2.1147

Gross Profit	$	306,460	$	0.9125	$	266,008	$	0.9211


	Amount (000)		Per Gallon		Amount (000)		Per Gallon
Other Petroleum Products
Volume (in millions of gallons)		34,092				27,818

Sales	$	104,715	$	3.0715	$	65,904	$	2.3692
Cost		96,510		2.8308		58,839		2.1153

Gross Profit	$	8,205	$	0.2407	$	7,065	$	0.2539


	Amount (000)				Amount (000)		Change
Total Product
Sales	$	1,289,870			$	942,646	$	347,224
Cost		975,205				669,573		(305,632	)

Gross Profit	$	314,665			$	273,073	$	41,592

For the nine months ended June 30, 2011, total product gross profit increased by $41.6 million to $314.7 million, as compared to $273.1 million for the nine months ended June 30, 2010, as the impact of higher home heating oil and propane volume ($43.3 million), and the additional gross profit from other petroleum products sold ($1.1 million) was reduced by slightly lower home heating oil and propane margins ($2.9 million).

(Increase) Decrease in the Fair Value of Derivative Instruments

During the ~~six~~nine months ended ~~March~~June 3130, 2011, the increase in the fair value of ~~derivative~~ derivative instruments resulted in the recording of a $2710.28 million net credit due to the expiration of certain hedged positions orand their realization to cost of product (a $54.09 million credit) and an increase in the market value for unexpired hedges (a $225.2 9 million credit).

During the ~~six~~nine months ended ~~March~~June 3130, 2010, the increase in the fair value of derivative ~~instruments~~ instruments resulted in the recording of a $85.18 million ~~net~~ credit due to the expiration of certain hedged positions orand their realization to cost of product (a $7.6.5 million credit), and ana ~~increase~~decrease in the market value for unexpired hedges (a $0.5 7 million ~~credit~~charge).

Cost of Installations and Service

During the ~~six~~nine months ended ~~March~~June 3130, 2011, cost of installations and service increased $1011.52 million, or 118.97%, to $98139.75 million, as compared to $88128.23 million for the ~~six~~nine months ended ~~March~~ June 3130, 2010, due primarily to an estimated $911.78 million of additional costs associated with acquisitions. Management views the service and installation department on a combined basis because many expenses ~~cannot be separated or allocated to either service~~ ~~or installation billings. Many administrative functions and direct expenses such as service technician time cannot be precisely allocated and generally remain in service costs.~~

~~Installation~~37 costs increased by $4.4 million to $31.0 million, or 85.6% of installation sales, during the six months ended March 31, 2011, versus $26.6 million, or 85.0% of installation sales during the six months ended March 31, 2010 largely due to acquisitions ($3.8 million). Service expenses increased by $6.1 million to $67.7 million, or 106.2% of service sales, during the six months ended March 31, 2011, from $61.5 million in the six months ended March 31, 2010, or 108.5% of sales largely due to acquisitions ($5.9 million). For the six months ended March 31, 2011, a combined profit from service and installation of $1.2 million was generated, compared to a combined loss of $0.1 million for the six months ended March 31, 2010.

cannot be separated or allocated to either service or installation billings. Many administrative functions and direct expenses such as service technician time cannot be precisely allocated and generally remain in service costs.

Installation costs increased by $4.7 million to $44.9 million, or 85.2% of installation sales, during the nine months ended June 30, 2011, versus $40.2 million, or 85.2% of installation sales during the nine months ended June 30, 2010, largely due to acquisitions ($4.5 million). Service expenses increased by $6.5 million to $94.6 million, or 98.9% of service sales, during the nine months ended June 30, 2011, from $88.1 million in the nine months ended June 30, 2010, or 100.7% of sales, largely due to acquisitions ($7.3 million). For the nine months ended June 30, 2011, a combined profit from service and installation of $8.8 million was generated, compared to a combined profit of $6.4 million for the nine months ended June 30, 2010.

Delivery and Branch Expenses

For the ~~six~~nine months ended ~~March~~June 3130, 2011, delivery and branch expenses increased $2332.20 million, or 18.68%, to $~~147~~201.98 million, compared to $~~124~~169.78 million for the ~~six~~nine months ended ~~March~~June 3130, 2010. Acquisitions added $1519.71 million in delivery and branch expenses. In the base business, delivery and branch expenses increased by $712.69 million due to higher delivery expenses of $23.94 million associated with the increase in volume and the numerous snow storms experienced induring the first ~~six~~nine months of fiscal 2011 ~~and~~along anwith an increase in bad debt expense and credit card ~~fee~~fees of $2.3.5 million associated with the 32increase in sales.3% The Partnership has increased its reserve rate for doubtful accounts for the nine months ended June 30, 2011, when compared to the nine months ended June 30, 2010 in response to an increase in the days sales outstanding, greater consumption due to colder temperatures and higher selling prices. Depending upon collections during the fourth quarter of fiscal 2011, this reserve rate will be adjusted accordingly. Insurance claims expense also rose by $25.8 million due to an increase in ~~part~~reserves tofor prior year claims and higher current year claim costs resulting from the extreme winter weather.

Depreciation and Amortization

For the ~~six~~nine months ended ~~March~~June 3130, 2011, depreciation and amortization ~~expenses~~expense increased by $2.25 million, or 3022.75%, to $913.37 million, as compared to $711.12 million for the ~~six~~nine months ended ~~March~~June 3130, 2010.

Depreciation expense was higher by $01.92 million due primarily to additional depreciation expense from depreciable property and equipment of fiscal 2010 acquisitions. Amortization expense was higher by $1.3 million as the additional amortization expense from fiscal 2010 and 2011 acquisitions of $2.38 million was ~~somewhat~~partially ~~reduced~~offset by a decline in amortization expense attributable to fiscal 2000, fiscal 2003 and fiscal ~~2000~~2004 acquisitions with either a 7 or 10 year life that became fully amortized in fiscal 2010 and fiscal 2011.

General and Administrative Expenses

For the ~~six~~nine months ended ~~March~~June 3130, 2011, general and administrative expenses decreased $0.59 million to $1015.25 million, from $1016.74 million for the ~~six~~nine months ended ~~March~~June 3130, 2010, primarily due to lower ~~professional~~acquisition ~~fees~~related expenses of $0.5 million and lower pension expenses ~~expense~~ relating to the Partnership’s frozen defined benefit pension plan of $0.6 million.

3338

Operating Income ~~(Loss)~~

For the ~~six~~nine months ended ~~March~~June 3130, 2011, operating income increased $2915.94 million to $~~131~~103.63 million, from $~~101~~87.79 million for the ~~six~~nine months ended ~~March~~June 3130, 2010, as an increase in gross product profit of $3441.36 million, a favorable change in the fair value of derivative instruments of $195.1 million and an improvement in service and installation profitability of $12.4 million was somewhat offset by operating expense increases (including depreciation and amortization) of $2433.96 million.

Interest Expense

For the ~~six~~nine months ended ~~March~~June 3130, 2011, interest expense increased by $01.42 million, or 410.7% to $812.5 million as compared to $811.13 million for the ~~six~~nine months ended ~~March~~June 3130, 2010. While average long-term debt increased by $820.91 million, the weighted average long-term borrowing rate declined from 10.25% to 9.314% and the corresponding interest expense ~~decreased~~increased by $0.25 million. In November 2010, the Partnership issued $125 million of 8.875% Senior Notes due 2017 and repaid $82.5 million of 10.25% Senior Notes due 2013.

During the ~~six~~nine months ended ~~March~~June 3130, 2011, the Partnership borrowed on average $2820.6 million under its revolving bank credit facility, or $2315.97 million higher than the ~~six~~nine months ended ~~March~~ June 3130, 2010 which drove an increase in interest expense of $0.5 million, despite a decline in the interest rate on these borrowings from 5.775% to 4.330%.

Interest Income

For the ~~six~~ nine months ended ~~March~~June 3130, 2011, interest income increased $01.40 million, or 3337.49%, to $13.8 million, as compared to $12.48 million for the ~~six~~nine months ended ~~March~~June 3130, 2010, due to higher finance charge income from acquisitions and higher accounts receivable balances.

Amortization of Debt Issuance Costs

For the ~~six~~nine months ended ~~March~~June 3130, 2011, amortization of debt issuance costs was unchanged at $12.40 million, ~~slightly higher~~ when compared to ~~$1.3 million for~~ the ~~six~~nine months ended ~~March~~June 3130, 2010.

~~Gain (~~Loss) on Redemption of Debt

In November 2010, wethe Partnership issued $125.0 million of Senior Notes due 2017. The Notes accrue interest at a rate of 8.875% and were priced at 99.350% for total gross proceeds of $124.2 million. A portion of the proceeds were used to redeem all of the remaining $82.5 million in face value of our 10.25% Senior Notes due 2013, at an average price of $101.70 per $100 of principal plus accrued interest, with the remainder available for general ~~partnership~~ partnership purposes. The Partnership recorded a loss of $1.7 million for this transaction . No subsequent Note repurchases have taken place in fiscal 2011.

During the ~~six~~nine months ended ~~March~~June 3130, 2010, the Partnership repurchased $50.0 million face value of its 10.25% Senior Notes due February 2013, at an average price of $101.707 per $100 of principal ~~plus~~ plus accrued interest. The Partnership recorded a loss of $1.1 million.

Income Tax Expense

For the ~~six~~nine months ended ~~March~~June 3130, 2011 income tax expense increased $~~12.~~6.2 million, to $5239.59 million, from $3933.97 million for the ~~six~~ nine months ended ~~March~~June 3130, 2010. The increase in income tax expense was mainly due to the higher pretax income of $2914.37 million. The current portion of income tax expense was $14.64 million or ~~12.0~~16% of pretax income.

Net Income

For the ~~six~~ nine months ended ~~March~~June 3130, 2011, net income increased $168.75 million to $6951.20 million, from $5242.5 million for the ~~six~~nine months ended ~~March~~June 3130, 2010, as the increase in operating income of $2915.94 million was slightly offset by an increase in income tax expense of $~~12.~~6.2 million.

Adjusted EBITDA

For the nine ~~six~~ months ended ~~March~~June 3130, 2011, Adjusted EBITDA increased by $1312.09 million, or 1213.9%, to $~~113~~106.72 million as the impact of colder temperatures of 78.6% and ~~the~~a $1617.51 million ofchange in Adjusted EBITDA provided by fiscal 2010 and 2011 acquisitions was ~~slightly~~somewhat ~~reduced~~offset by net customer attrition in the base business, higher delivery and branch expenses attributable to the numerous snowstorms in our marketing areas, an increase in bad debt expense and credit card processing fees due to the increase in sales driven largely by the increase in wholesale product cost and an increase in insurance claims expense due in part to the severe winter weather.


	Nine Months Ended June 30,
(in thousands)	2011			2010
Net income	$	51,042		$	42,549
Plus:
Income tax expense		39,892			33,681
Amortization of debt issuance cost		2,044			1,988
Interest expense, net		8,666			8,508
Depreciation and amortization		13,696			11,179

EBITDA from continuing operations		115,340			97,905

(Increase) / decrease in the fair value of derivative instruments		(10,844	)		(5,770	)
Losses on redemption of debt		1,700			1,132

Adjusted EBITDA		106,196			93,267

Add / (subtract)
Income tax expense		(39,892	)		(33,681	)
Interest expense, net		(8,666	)		(8,508	)
Provision for losses on accounts receivable		10,093			6,570
Increase in accounts receivables		(92,107	)		(41,717	)
Decrease in inventories		6,846			1,871
Decrease in customer credit balances		(45,525	)		(44,425	)
Change in deferred taxes		25,464			30,368
Change in other operating assets and liabilities		18,517			10,502

Net cash provided by (used in) operating activities	$	(19,074	)	$	14,247


Net cash used in investing activities	$	(10,019	)	$	(71,187	)


Net cash provided by (used in) financing activities	$	18,568		$	(94,269	)

attributable to the numerous snowstorms in our marketing areas, an increase in bad debt expense and credit card processing fees due to the increase in sales driven largely by the increase in wholesale product cost and an increase in insurance claims expense due in part to the severe winter weather.

	Six Months Ended March 31,
(in thousands)	2011			2010
Net income	$	69,239		$	52,540
Plus:
Income tax expense		52,479			39,913
Amortization of debt issuance cost		1,426			1,328
Interest expense, net		6,766			6,826
Depreciation and amortization		9,276			7,096
EBITDA from continuing operations		139,186			107,703
(Increase) / decrease in the fair value of derivative instruments		(27,167	)		(8,094	)
(Gains) / losses on redemption of debt		1,700			1,132
Adjusted EBITDA		113,719			100,741
Add / (subtract)
Income tax expense		(52,479	)		(39,913	)
Interest expense, net		(6,766	)		(6,826	)
Provision for losses on accounts receivable		7,873			5,482
Increase in accounts receivables		(213,123	)		(135,290	)
Decrease in inventories		27,835			2,436
Decrease in customer credit balances		(52,242	)		(53,098	)
Change in deferred taxes		37,858			35,788
Change in other operating assets and liabilities		34,633			14,632
Net cash used in operating activities	$	(102,692	)	$	(76,048	)
Net cash used in investing activities	$	(4,444	)	$	(2,632	)
Net cash provided by (used in) financing activities	$	57,894		$	(62,907	)

EBITDA and Adjusted EBITDA (non-GAAP financial measures)

•

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.

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;

•

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 may 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 customers receive deliveries and pay for products purchased within our payment terms, and cash is generally provided by operating activities during the spring and summer (our third and fourth quarters) when customer payments exceed deliveries. For the ~~six~~nine months ended ~~March~~June 3130, 2011, cash used in operating activities increased by $2633.73 million to $~~102~~19.71 million, when compared to $7614.02 million of cash ~~used~~provided inby operating activities during the ~~six~~ nine months ended ~~March~~June 3130, 2010, as a favorable change in cash generated from operations of $45.92 million, a reduction in inventory levels of $255.40 million, ~~lower cash needs to fund trade payables of $6.1 million~~ and ~~the~~other ~~favorable~~changes ~~timing of certain cash payments (options, interest, insurance and income taxes)~~ totaling $136.9 million was reduced by an increase in cash needs to fund accounts receivable of $7750.04 million. The increase in accounts receivable can be attributed to an increase in volume due to acquisitions, colder temperatures and an increase in ~~wholesale~~average ~~product~~selling ~~costs~~prices. Days sales outstanding as of ~~March~~June 3130, 2011 were ~~35.6~~60 days as compared to ~~32.3~~57 days at ~~March~~June 3130, 2010 and ~~29.4~~48 days at ~~March~~June 3130, 2009. ~~March~~The ~~2011 was approximately 30% colder than March 2010, which resulted in greater consumption and an~~ increase in days sales outstanding. Atat ~~March~~June 3130, 2011, wewas ~~reduced~~largely ~~our~~driven ~~petroleum products inventory~~ by ~~14.1 million~~amounts ~~gallons~~due tofrom ~~8.1 million~~customers ~~gallons~~on ~~when~~our ~~compared~~budget ~~to March 31,~~payment ~~2010~~plan. ~~This~~Days ~~reduction~~sales outstanding infrom ~~inventory~~budget ~~levels~~customers ~~was~~were ~~due~~73 indays ~~part~~at toJune 30, ~~the~~2011 ~~impact~~as ofcompared ~~colder~~to ~~temperatures~~61 ondays ~~volume~~as ~~sales~~of ~~for~~June 30, ~~the~~2010. ~~month~~The impact of ~~March~~colder ~~for~~temperatures ~~the~~coupled ~~respective~~with ~~periods.~~an ~~The~~increase ~~decrease~~ in ~~trade~~home ~~payables~~heating isoil ~~primarily~~costs ~~due~~resulted ~~to the increase~~ in our ~~trade~~ ~~credit~~budget tocustomers ~~$71.6~~owing ~~million.~~more ~~Towards~~at June 30, ~~the~~2011 ~~end~~when ofcompared ~~fiscal~~to June 30, 2010. Historically, during the ~~Partnership~~fourth ~~restructured~~fiscal ~~its~~quarter ~~option~~our ~~program,~~budget ~~which~~customers ~~impacted~~pay down the ~~payment~~balances ~~terms~~due ~~for~~on ~~these~~their ~~options~~accounts. ~~The~~For ~~Partnership~~example, ~~now~~as ~~pays~~of ~~for~~September 30, ~~these~~2010 ~~options~~and asSeptember 30 ~~they~~2009, ~~expire~~days sales ~~rather~~outstanding ~~than~~from atbudget ~~the~~customers ~~time~~were ~~the hedge~~28 isdays ~~entered~~and ~~into~~23 days, respectively.

Investing Activities

During the ~~six~~nine months ended ~~March~~June 3130, 2011, we spent $23.78 million for fixed assets as we invested in computer hardware and software ($1.16 million), refurbished certain physical plants ($0.85 million) and made additions to our fleet and other equipment ($01.87 million). We also completed ~~two~~three acquisitions for $16.83 million.

During the ~~six~~nine months ended ~~March~~June 3130, 2010, ~~our~~we completed acquisitions for $67.8 million, including working capital ~~expenditures~~of ~~totaled~~$4.0 million. We allocated $265.6 million of the gross purchase price to intangible assets and $7.2 million to fixed assets and recorded a deferred tax liability of $9.0 million. In addition, we spent $3.6 million for fixed assets, as we invested in computer hardware and software ($01.86 million), refurbished certain physical plants ($0.14 million) and made additions to our fleet and other equipment ($1.86 million).

Financing Activities

During the ~~six~~nine months ended ~~March~~June 3130, 2011, we sold $125.0 million 8.875% Senior Notes due 2017 at a price of 99.350%. A portion of the net proceeds were used on December 20, 2010, to repurchase $82.5 million in face value of 10.25% Senior Notes due February 2013. After paying expenses of $3.8 million and a call premium of $1.4 million, our cash balance increased by $36.5 million, which can be utilized for general partnership purposes. Also during the first half of fiscal 2011, we paid distributions of $10.2 million, borrowed $88.4 million under our revolving credit facility and repaid $56.8 million of these borrowings during the period. As of March 31, 2011, the Partnership had borrowed $31.6 million under our revolving credit facility.

3642

~~During~~ utilized ~~the~~for ~~first~~general ~~six~~partnership ~~months~~purposes. ofIn ~~fiscal~~June ~~2010~~2011, ~~the~~we ~~Partnership~~amended ~~repurchased~~and ~~5.2 million common~~extended ~~units~~our ~~for~~bank ~~$20.8~~agreement ~~million~~to inJune 2016. In connection with ~~the~~this ~~unit~~extension ~~repurchase~~we ~~plan program and~~ paid ~~distributions~~fees ~~to the unit holders~~ of $~~10.~~2.5 million. ~~During~~Also during the fiscal ~~six~~2011, ~~months~~we ~~ended~~paid ~~March~~distributions of $15.4 31million, ~~2010, we~~ borrowed $3688.84 million under our revolving credit facility and repaid $1788.74 million ~~during the period. As~~ of ~~March 31,~~these ~~2010,~~borrowings during the ~~Partnership had $19~~period.1 ~~million borrowed under its revolving credit facility. This amount was subsequently repaid by May 2010.~~

OnDuring ~~February~~the nine months of fiscal 2010, the Partnership repurchased 6.9 19million common units for $27.9 million in connection with the unit repurchase plan program and paid distributions to the unit holders of $15.4 million. During the nine months ended June 30, 2010, we borrowed and repaid $36.8 million under our revolving credit facility. In February 2010, the Partnership redeemed $50.0 million face value of its outstanding 10.25% Senior Notes due in 2013 at a price equal to 101.708% of face value.

Liquidity and Capital Resources

Our ability to satisfy our financial obligations 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 wholesale heating oil prices to customers, the effects of high net customer attrition, conservation and other economic and geo-political factors, most of which are beyond our control. In the near term, capital requirements are expected to be provided by cash flows from operating activities, cash on hand at ~~March~~June 3130, 2011, or a combination thereof. We anticipate that working capital will be financed by our revolving credit facility. To the extent future capital requirements exceed cash on hand plus cash flows from operating activities, we ~~anticipate~~could seek ~~that~~to ~~working~~offer ~~capital~~and ~~will~~sell bedebt ~~financed~~or byequity securities under our ~~revolving~~$250 ~~credit~~million ~~facility~~shelf registration statement.

~~Our~~In June 2011, we amended and restated our asset based revolving ~~credit~~facility under which our subsidiary, Petroleum Heat and Power Co., is the borrower, and we are an additional loan party, which extended the maturity date from July 2012 to June 2016. The amended facility provides us with the ability to borrow up to $~~240~~250 million ($~~290~~300 million during the heating season from November 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 $50100 million without the consent of the bank group. However, the bank group is not obligated to fund the $50100 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 ~~March~~June 3130, 2011, $~~31.6 million was outstanding for working capital borrowings and $~~46.7 million in letters of credit were outstanding, of which $46.4 million are for current and future insurance reserves and bonds and $0.3 million are for seasonal inventory purchases and other working capital purposes. ~~Our revolving credit facility expires on July 2, 2012 and we are in the process of extending this agreement.~~

Under the terms of the credit facility, we must maintain at all times either availability (borrowing base less amounts borrowed and letters of credit issued) of $4352.5 million (1517.5% of the maximum facility size) or a fixed charge coverage ratio (as defined in the credit agreement) of not less than 1.1x. As of ~~March~~June 3130, 2011, availability, as defined in the amended and restated credit agreement, was $~~181~~155.59 million and we were in compliance with the fixed charge coverage ratio. The fixed charge coverage ratio is calculated based upon Adjusted EBITDA. In the event that we are not able to comply with these covenants it could have a material adverse effect on our liquidity and results of operations. For additional information concerning the revolving credit facility, see Note 6 of the Notes to the Condensed Consolidated Financial Statements.

~~The~~43 scheduled interest payment on our 8.875% Senior Notes for the remainder of fiscal 2011 is $6.0 million, and maintenance capital expenditures for fixed assets are estimated to be approximately $1.5 to $2.5 million, excluding the capital requirements for leased fleet. Based on the funding levels required by the Pension Protection Act of 2006, and certain actuarial assumptions, we estimate that the Partnership may make cash contributions to fund its frozen defined benefit pension obligations of approximately $2.1 million for the balance of fiscal 2011. Should the Partnership maintain its current distribution rate, we would pay distributions of approximately $10.5 million for the remainder of fiscal 2011. In addition, we will continue to seek strategic acquisitions and will repurchase units as authorized under our unit repurchase plan.

Partnership Distribution Provisions

We are required to make distributions in an amount equal to our Available Cash, as defined in our Partnership Agreement, no more than 45 days after the end of each fiscal quarter, to holders of record on the applicable record dates. Available Cash, as defined in our Partnership Agreement, generally means all cash on hand at the end of the relevant fiscal quarter less the amount of cash reserves established by the Board of Directors of our general partner in its reasonable discretion for future cash requirements. These reserves are established for the proper conduct of our business, including acquisitions, the payment of debt principal and interest and for distributions during the next four quarters and to comply with applicable laws and the terms of any debt agreements or other agreements to which we are subject. Under the terms of our credit facility, we must have availability of at least $40 million and a fixed charge coverage ratio of 1.15x to pay the minimum quarterly distribution of $0.0675. Any distribution in excess of the minimum quarterly distribution requires us to have a fixed charge coverage ratio of 1.25x. These tests restrict the amount of cash that we can use to pay distributions with

The scheduled interest payment on our 8.875% Senior Notes for the remainder of fiscal 2011 ~~respect~~is $5.5 million, and maintenance capital expenditures for fixed assets are estimated to ~~any~~be ~~fiscal~~approximately ~~quarter~~$1.0 ~~The~~to ~~Board~~$2.0 million, excluding the capital requirements for leased fleet. Based on the funding levels required by the Pension Protection Act of 2006, ~~Directors~~and certain actuarial assumptions, we estimate that the Partnership will make cash contributions to fund its frozen defined benefit pension obligations of ~~our~~approximately ~~General~~$1.4 ~~Partner~~million ~~reviews~~for the ~~level~~balance of ~~Available~~fiscal ~~Cash~~2011. ~~each~~Should ~~quarter~~the ~~based~~Partnership maintain ~~upon~~its ~~information~~current ~~provided~~distribution byrate, ~~management~~we would pay distributions of approximately $5.3 million for the remainder of fiscal 2011. In addition, we will continue to seek strategic acquisitions and may repurchase units as authorized under our unit repurchase plan.

OnPartnership ~~April 14,~~Distribution ~~2011,~~Provisions ~~we declared a quarterly distribution of $0.0775 on all of our common units, payable on May 13, 2011 to holders of record on May 5, 2011.~~

We are required to make distributions in an amount equal to our Available Cash, as defined in our Partnership Agreement, no more than 45 days after the end of each fiscal quarter, to holders of record on the applicable record dates. Available Cash, as defined in our Partnership Agreement, generally means all cash on hand at the end of the relevant fiscal quarter less the amount of cash reserves established by the Board of Directors of our general partner in its reasonable discretion for future cash requirements. These reserves are established for the proper conduct of our business, including acquisitions, the payment of debt principal and interest and for distributions during the next four quarters and to comply with applicable laws and the terms of any debt agreements or other agreements to which we are subject. Under the terms of our credit facility, we must have availability of at least $52.5 million and a fixed charge coverage ratio of 1.15x to pay any distribution. This test restricts the amount of cash that we can use to pay a distribution with respect to any fiscal quarter. The Board of Directors of our General Partner reviews the level of Available Cash each quarter based upon information provided by management.

On July 14, 2011, we declared a quarterly distribution of $0.0775 on all of our common units, payable on August 12, 2011 to holders of record on August 4, 2011.

Contractual Obligations and Off-Balance Sheet Arrangements

There has been no material change to Contractual Obligations and Off-Balance Sheet Arrangements since September 30, 2010, and therefore, the table has not been included in this Form 10-Q.

Recent Accounting Pronouncements

The following new accounting standards are currently being evaluated by the Partnership, and are more fully described in Note 3. Summary of Significant Accounting Policies - Recent Accounting Pronouncements, of the consolidated financial statements:

•

Accounting Standards Update (“ASU”) No. 2011-04, Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. generally accepted accounting principles (“U.S. GAAP”) and the International Financial Reporting Standards (“IFRS”).

•

ASU No. 2011-05, Comprehensive Income (Topic 220): Presentation of Comprehensive Income.

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 ~~March~~June 3130, 2011, we had outstanding borrowings totaling $~~155~~125.80 million (excluding discounts), ofnone of which ~~approximately $31.6 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 impact on future cash flows would be a decrease of $0.3 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 ~~March~~June 3130, 2011, the potential impact on our hedging activity would be to increase the fair market value of these outstanding derivatives by $117.97 million to a fair market value of $3818.0 million; and conversely a hypothetical ten percent decrease in the cost of product would decrease the fair market value of these outstanding derivatives by $(~~10.~~5.2) million to a fair market value of $155.61 million.

Item 4.

Controls and Procedures

(a) Evaluation of disclosure controls and procedures.

The General Partner’s principal executive officer and its principal 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 ~~March~~June 3130, 2011. Based on that evaluation, such principal executive officer and principal financial officer concluded that the Partnership’s disclosure controls and procedures were effective as of ~~March~~June 3130, 2011 at the reasonable level of assurance. 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 principal executive and principal financial officer, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

(b) Change in Internal Control over Financial Reporting.

OnNo May 10, 2010, the Partnership completed the acquisition of Champion Energy Corporation (“CEC”). The Partnership is in process of integrating CEC. The Partnership is analyzing, evaluating and, where necessary, is implementing changes in controls and procedures relating to the CEC business as integration proceeds. As a result, this process may result in additions or changes to our internal control over financial reporting. Otherwise, there was no change in the Partnership’s internal control over financial reporting occurred during the Partnership’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect the Partnership’s internal control over financial reporting.

~~(c)~~On ~~The~~May 10, ~~General~~2010, ~~Partner and~~ the Partnership ~~believe~~completed ~~that~~the aacquisition ~~controls~~of ~~system,~~Champion noEnergy ~~matter~~Corporation ~~how~~(CEC). ~~well~~The ~~designed~~Partnership ~~and~~completed ~~operated, cannot provide absolute assurance that~~ the ~~objectives~~integration of ~~the~~CEC’s ~~controls~~operations ~~system~~with ~~are~~the ~~met,~~Partnership’s ~~and~~internal ~~no evaluation of controls can provide absolute assurance that all~~ control ~~issues~~systems ~~and~~as ~~instances of fraud~~June 30, ~~if any, within a company have been detected~~2011.

3845

c) The General Partner and the Partnership believe that a controls system, no matter how well designed and operated, cannot provide absolute assurance that the objectives of the controls system are met, and no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within a Partnership have been detected. Therefore, a 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. Our disclosure controls and procedures are designed to provide such reasonable assurances of achieving our desired control objectives, and the principal executive officer and principal financial officer of our general partner have concluded, as of ~~March 31~~June 30, 2011, that our disclosure controls and procedures were effective in achieving that level of reasonable assurance.

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

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 and set forth under Item 1A. “Risk Factors” in our Fiscal 2010 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. Additional risks and uncertainties not presently known to us or that we currently believe not to be material may also adversely impact our business, results of operations, financial position and cash flows.

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

See Note 2. to the Consolidated Financial Statements for information concerning the Partnership’s repurchase of common units in the ~~six~~nine months ended ~~March~~June 3130, 2011.

Item 6.

Exhibits

(a)	Exhibits Included Within:

31.1		Rule 13a-14(a) Certification, Star Gas Partners, L.P.
31.2		Rule 13a-14(a) Certification, Star Gas Finance Company
31.3		Rule 13a-14(a) Certification, Star Gas Partners, L.P.
31.4		Rule 13a-14(a) Certification, Star Gas Finance Company
32.1		Section 906 Certification.
32.2		Section 906 Certification.
101		The following materials from the Star Gas Partners, L.P. Quarterly Report on Form 10-Q for the quarter ended June 31, 2011 formatted in Extensible Business Reporting Language (XBRL): (i) the Condensed Consolidated Statements of Operations, (ii) the Condensed Consolidated Balance Sheets, (iii) the

3947


		Condensed Consolidated Statements of Cash Flows and (iv) 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.

#	Filed herewith. In accordance with Rule 406T of Regulation S-T, these interactive data files are deemed “not filed” for purposes of section 18 of the Exchange Act, and otherwise are not subject to liability under that section.

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	Executive Vice President, Chief	~~May~~August 43, 2011
Richard F. Ambury	Financial Officer, Treasurer and Secretary
	Kestrel Heat LLC
	(Principal Financial Officer)
Signature	Title	Date
/S/ RICHARD G. OAKLEY	Vice President - Controller	~~May~~August 43, 2011
Richard G. Oakley	Kestrel Heat LLC
	(Principal Accounting Officer)
Star Gas Finance Company (Registrant)
Signature	Title	Date
/S/ RICHARD F. AMBURY	Executive Vice President Chief	~~May~~August 43, 2011
Richard F. Ambury	Financial Officer, Treasurer and Secretary
	(Principal Financial Officer)
Signature	Title	Date
/S/ RICHARD G. OAKLEY	Vice President - Controller	~~May~~August 43, 2011
Richard G. Oakley	(Principal Accounting Officer)

4049

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

(a)Table toof April 30, 2011 Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Filing Compare · STAR GAS FINANCE CO