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 ~~December~~March 31, ~~2010~~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 ~~January~~April 3130, 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 December 31, 2010 (unaudited) and September 30, 2010		3
Condensed Consolidated Balance Sheets as of March 31, 2011 (unaudited) and September 30, 2010		3
Condensed Consolidated Statements of Operations for the three months ended December 31, 2010 and December 31, 2009 (unaudited)		4
Condensed Consolidated Statements of Operations for the three and six months ended March 31, 2011 and March 31, 2010 (unaudited)		4
Condensed Consolidated Statement of Partners’ Capital and Comprehensive Income for the three months ended December 31, 2010 (unaudited)		5
Condensed Consolidated Statement of Partners’ Capital and Comprehensive Income for the six months ended March 31, 2011 (unaudited)		5
Condensed Consolidated Statements of Cash Flows (unaudited) for the three months ended December 31, 2010 and December 31, 2009		6
Condensed Consolidated Statements of Cash Flows (unaudited) for the six months ended March 31, 2011 and March 31, 2010		6
Notes to Condensed Consolidated Financial Statements (unaudited)		7-18
Item 2—Management’s Discussion and Analysis of Financial Condition and Results of Operations		19-3038
Item 3—Quantitative and Qualitative Disclosures About Market Risk		3038
Item 4—Controls and Procedures		3038
Part II Other Information:
Item 1—Legal Proceedings		3139
Item 1A—Risk Factors		3139
Item 2—Unregistered Sales of Equity Securities and Use of Proceeds		31
Item 2— Unregistered Sales of Equity Securities and Use of Proceeds		39
Item 6—Exhibits		3139
Signatures		3240

STAR GAS PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands)	~~December~~March 31,~~2010~~2011			September 30,2010
	(unaudited)
ASSETS
Current assets
Cash and cash equivalents	$	1311,~~804~~820		$	61,062
Receivables, net of allowance of $7,534 and $5,443, respectively		182,965			70,443
Receivables, net of allowance of $11,177 and $5,443, respectively		275,699			70,443
Inventories		7739,~~357~~216			66,734
Fair asset value of derivative instruments		1826,~~092~~264			7,158
Current deferred tax asset, net		63,~~599~~106			20,247
Prepaid expenses and other current assets		3031,~~114~~386			21,219
Total current assets		~~328~~387,~~931~~491			246,863
Property and equipment, net		4544,~~078~~493			44,712
Goodwill		~~199~~198,~~052~~845			199,052
Intangibles, net		5653,~~383~~821			58,894
Long-term deferred tax asset, net		245,~~932~~261			26,551
Deferred charges and other assets, net		98,~~425~~641			6,436
Total assets	$	~~663~~698,~~801~~552		$	582,508
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities
Accounts payable	$	3322,~~407~~725		$	16,626
Revolving credit facility borrowings		1331,~~076~~593			—
Fair liability value of derivative instruments		—			1,586
Accrued expenses and other current liabilities		7896,~~672~~660			68,854
Unearned service contract revenue		4944,~~233~~308			40,110
Customer credit balances		4516,~~737~~633			68,762
Total current liabilities		~~220~~211,~~125~~919			195,938
Long-term debt		124,~~198~~219			82,770
Other long-term liabilities		2322,~~510~~618			23,889
Partners’ capital
Common unitholders		~~322~~365,~~687~~934			307,092
General partner		~~348~~525			290
Accumulated other comprehensive loss, net of taxes		(2726,~~067~~663	)		(27,471	)
Total partners’ capital		~~295~~339,~~968~~796			279,911
Total liabilities and partners’ capital	$	~~663~~698,~~801~~552		$	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 December 31,
	Three Months Ended March 31,						Six Months Ended March 31,
(in thousands, except per unit data - unaudited)	~~2010~~2011			~~2009~~2010			2011			2010
Sales:
Product	$	~~404~~686,~~968~~452		$	~~301~~510,~~765~~713		$	1,091,420		$	812,478
Installations and service		5445,~~533~~413			4741,~~054~~019			99,946			88,073
Total sales		~~459~~731,~~501~~865			~~348~~551,~~819~~732			1,191,366			900,551
Cost and expenses:
Cost of product		~~301~~519,~~672~~154			~~214~~361,~~515~~713			820,826			576,228
Cost of installations and service		5246,~~622~~075			4542,~~672~~517			98,697			88,189
(Increase) decrease in the fair value of derivative instruments		(13,~~906~~261	)		(34,~~392~~702	)		(27,167	)		(8,094	)
Delivery and branch expenses		6581,~~961~~975			5667,~~822~~872			147,936			124,694
Depreciation and amortization expenses		4,~~577~~699			3,~~535~~561			9,276			7,096
General and administrative expenses		45,~~924~~264			5,~~053~~646			10,188			10,699
Operating income		4387,~~651~~959			2675,~~614~~125			131,610			101,739
Interest expense		(4,~~220~~319	)		(43,~~270~~885	)		(8,539	)		(8,155	)
Interest income		~~532~~1,241			~~394~~935			1,773			1,329
Amortization of debt issuance costs		(~~694~~732	)		(~~656~~672	)		(1,426	)		(1,328	)
Loss on redemption of debt		~~(1,700~~—	)		—(1,132	)		(1,700	)		(1,132	)
Income before income taxes		3784,~~569~~149			2270,~~082~~371			121,718			92,453
Income tax expense		1735,~~011~~468			1029,~~077~~836			52,479			39,913
Net income	$	2048,~~558~~681		$	1240,~~005~~535		$	69,239		$	52,540
General Partner’s interest in net income		99236			54187			335			241
Limited Partners’ interest in net income	$	2048,~~459~~445		$	1140,~~951~~348		$	68,904		$	52,299
Basic and Diluted income per Limited Partner Unit (1)	$	0.2661		$	0.1548		$	0.86		$	0.62
Weighted average number of Limited Partner units outstanding:
Basic and Diluted		67,078			7270,~~661~~302			67,078			71,494

(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		~~Common~~			~~GeneralPartner~~			~~Accum. OtherComprehensiveIncome (Loss)~~			~~TotalPartners’Capital~~
Balance as of September 30, 2010		67,078		326	$	307,092		$	290		$	(27,471	)	$	279,911
Comprehensive income (unaudited):
Net income		—		—		2068,~~459~~904			99335			—			2069,~~558~~239
Unrealized gain on pension plan obligation		—		—		—			—			~~691~~1,382			~~691~~1,382
Tax effect of unrealized gain on pension plan		—		—		—			—			(~~287~~574	)		(~~287~~574	)
Total comprehensive income		—		—		2068,~~459~~904			99335			~~404~~808			2070,~~962~~047
Distributions		—		—		(410,~~864~~062	)		(41100	)		—			(410,~~905~~162	)
Balance as of December 31, 2010 (unaudited)		67,078		326	$	322,687		$	348		$	(27,067	)	$	295,968
Balance as of March 31, 2011 (unaudited)		67,078		326	$	365,934		$	525		$	(26,663	)	$	339,796

See accompanying notes to condensed consolidated financial statements.

STAR GAS PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

	Three Months EndedDecember 31,
	Six Months EndedMarch 31,
(in thousands - unaudited)	~~2010~~2011			~~2009~~2010
Cash flows provided by (used in) operating activities:
Net income	$	2069,~~558~~239		$	1252,~~005~~540
Adjustment to reconcile net income to net cash provided by (used in) operating activities:
(Increase) decrease in fair value of derivative instruments		(1327,~~906~~167	)		(38,~~392~~094	)
Depreciation and amortization		510,~~271~~702			48,~~191~~424
Loss on redemption of debt		1,700			—1,132
Provision for losses on accounts receivable		27,~~648~~873			25,~~148~~482
Change in deferred taxes		1437,~~980~~858			935,~~482~~788
Changes in operating assets and liabilities:
Increase in receivables		(~~115~~213,~~161~~123	)		(76135,~~952~~290	)
Increase in inventories		(10,324	)		(9,387	)
Decrease in inventories		27,835			2,436
Increase in other assets		(7,358	)		(10,282	)
(Increase) decrease in other assets		(3,431	)		7,105
Increase in accounts payable		166,~~781~~099			~~8,114~~33
Decrease in customer credit balances		(2352,~~134~~242	)		(2153,~~790~~098	)
Increase in other current and long-term liabilities		1931,~~235~~965			127,~~876~~494
Net cash used in operating activities		(88102,~~710~~692	)		(7276,~~987~~048	)
Cash flows provided by (used in) investing activities:
Capital expenditures		(12,~~558~~721	)		(12,~~636~~664	)
Proceeds from sales of fixed assets		1468			81155
Acquisitions		(1,~~638~~791	)		—
Net cash used in investing activities		(3,182	)		(1,555	)
Earnout		—			(123	)
Net cash used in investing activities		(4,444	)		(2,632	)
Cash flows provided by (used in) financing activities:
Revolving credit facility borrowings		1388,~~076~~416			—36,754
Revolving credit facility repayments		—(56,823	)		—(17,660	)
Repayment of debt		(82,499	)		—(50,854	)
Proceeds from the issuance of debt		124,188			—
Debt extinguishment costs		(1,409	)		—
Distributions		(410,~~905~~162	)		(510,~~059~~246	)
Unit repurchase		—			(1620,~~888~~771	)
Deferred charges		(3,817	)		—(130	)
Net cash provided by (used in) financing activities		4457,~~634~~894			(2162,~~947~~907	)
Net decrease in cash and cash equivalents		(4749,~~258~~242	)		(96141,~~489~~587	)
Cash and cash equivalents at beginning of period		61,062			195,160
Cash and cash equivalents at end of period	$	1311,~~804~~820		$	9853,~~671~~573

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 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 ~~December~~March 31, ~~2010~~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 ~~December~~March 31, ~~2010~~2011 served approximately ~~414~~408,000 full-service residential and commercial home heating oil and propane customers. Petro also sold home heating oil, gasoline and diesel fuel to approximately 3740,000 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

(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 month period ended ~~December~~March 31, ~~2010~~2011 and ~~December~~March 31, ~~2009~~2010 are not necessarily indicative of the results to be expected for the ~~full~~ 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.

Cost of Installations and Service

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 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, 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.

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 ~~EndedDecember~~EndedMarch 31,				Six Months EndedMarch 31,
	2010		2009
	2011		2010		2011		2010
Net income	$	2048,~~558~~681	$	1240,~~005~~535	$	69,239	$	52,540
Less General Partners’ interest in net income		99236		54187		335		241
Net income available to limited partners		2048,~~459~~445		1140,~~951~~348		68,904		52,299
Less dilutive impact of theoretical distribution of earnings underFASB ASC 260-10-45-60		2,774		994
Less dilutive impact of theoretical distribution of earnings under FASB ASC 260-10-45-60		7,308		6,594		11,320		7,929
Limited Partner’s interest in net income underFASB ASC 260-10-45-60	$	17,685	$	10,957
Limited Partner’s interest in net income under FASB ASC 260-10-45-60	$	41,137	$	33,754	$	57,584	$	44,370
Per unit data:
Basic and diluted net income available to limited partners	$	0.3072	$	0.1657	$	1.03	$	0.73
Less dilutive impact of theoretical distribution of earnings underFASB ASC 260-10-45-60		0.04		0.01
Less dilutive impact of theoretical distribution of earnings under FASB ASC 260-10-45-60		0.11		0.09		0.17		0.11
Limited Partner’s interest in net income underFASB ASC 260-10-45-60	$	0.26	$	0.15
Limited Partner’s interest in net income under FASB ASC 260-10-45-60	$	0.61	$	0.48	$	0.86	$	0.62
Weighted average number of Limited Partner units outstanding		67,078		7270,~~661~~302		67,078		71,494

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.

	December 31,		September 30,
(in thousands)	March 31,2011		September 30,2010
(in thousands)	2010		2010
Heating oil and other fuels	$	23,828	$	51,678
Heating oil and other fuels	$	61,938	$	51,678
Fuel oil parts and equipment		15,388		15,056
Fuel oil parts and equipment		15,419		15,056
	$	39,216	$	66,734
	$	77,357	$	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 December 31, 2010, the Partnership had 2.9 million gallons of physical inventory and had 6.6 million gallons of swap contracts to buy heating oil; 34.0 million gallons of call options; 5.6 million gallons of put options and 64.0 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 December 31, 2010 had 14.1 million gallons of future contracts to buy heating oil; 22.0 million gallons of future contracts to sell heating oil; and 29.4 million gallons of swap contracts to sell heating oil. To hedge a portion of its internal fuel usage, the Partnership as of December 31, 2010, had 1.1 million gallons of swap contracts to buy gasoline and 0.9 million gallons of swap contracts to buy diesel.

ToDerivatives hedge a substantial majority of the purchase price associated with heating oil gallons anticipated to be sold to its price-protected customers, as of December 31, 2009, the Partnership had 2.3 million gallons of swap contracts to buy heating oil; 0.1 million gallons of futures contracts to sell heating oil; 87.9 million gallons of call options; 1.3 million gallons of put options and ~~17.2 million~~Hedging ~~net~~– ~~gallons~~Disclosures ~~of synthetic calls. To hedge the inter-month differentials for our price-protected customers, its physical inventory on hand,~~ and ~~inventory~~ inFair ~~transit,~~Value the Partnership as of December 31, 2009 had 10.6 million gallons of future contracts to buy heating oil; 11.3 million gallons of future contracts to sell heating oil; and 30.2 million gallons of swapMeasurements contracts to sell heating oil. To hedge a portion of its internal fuel usage, the Partnership as of December 31, 2009, had 1.1 million gallons of swap contracts to buy gasoline and 0.9 million gallons of swap contracts to buy diesel.

The Partnership’s uses derivative instruments ~~are~~such ~~with~~as ~~the following counterparties: Cargill~~futures, ~~Inc.~~options, ~~Societe Generale, Key Bank National Association, JPMorgan Chase Bank, NA, Bank of America, N.A., Newedge USA, LLC,~~ and ~~Wells~~swap ~~Fargo Bank~~agreements, ~~N.A.~~in ~~The~~order ~~Partnership~~to ~~assesses~~mitigate exposure ~~counterparty~~to ~~credit~~market risk ~~and~~associated ~~maintains master netting arrangements~~ with ~~its counterparties to help manage~~ the ~~risks,~~purchase ~~and~~of ~~records~~home ~~its~~heating ~~derivative~~oil ~~positions~~for onprice-protected acustomers, ~~net~~physical ~~basis.~~inventory ~~Based~~ on ~~its assessment~~hand, ~~the~~inventory ~~Partnership considers counterparty credit risk to be low. At December 31, 2010, the aggregate cash posted as collateral~~ in ~~the~~transit ~~normal~~and ~~course~~priced ~~of business~~purchase ~~at counterparties was $0~~commitments.7 million. Positions with counterparties who are also parties to our revolving credit facility are collateralized under that facility. As of December 31, 2010, $3.5 million of hedging losses was secured under the credit facility.

~~FASB~~To ~~ASC~~hedge ~~815-10-05~~a ~~Derivatives~~substantial ~~and~~majority ~~Hedging~~of ~~topic,~~the ~~established~~purchase ~~accounting~~price ~~and~~associated ~~reporting~~with ~~standards requiring~~heating ~~that~~oil ~~derivative~~gallons ~~instruments~~anticipated to be ~~recorded~~sold atto ~~fair~~its ~~value~~price-protected customers, ~~and~~as ~~included~~of inMarch 31, 2011, the ~~consolidated~~Partnership ~~balance~~had ~~sheet~~0.7 million asgallons ~~assets~~of orphysical ~~liabilities,~~inventory ~~along~~and ~~with~~had ~~qualitative~~3.4 million ~~disclosures~~gallons ~~regarding~~of ~~the~~swap ~~derivative~~contracts ~~activity~~to buy heating oil; 8.3 million Togallons ~~the~~of ~~extent~~call ~~derivative~~options; ~~instruments~~2.9 million gallons of put ~~designated~~options asand ~~cash~~36.1 million ~~flow~~net ~~hedges~~gallons ~~are~~of ~~effective~~synthetic ~~and~~calls. To hedge the ~~standard’s~~inter-month ~~documentation~~differentials ~~requirements~~for ~~have~~our ~~been~~price-protected ~~met~~customers, ~~changes~~its inphysical ~~fair~~inventory ~~value~~on ~~are~~hand, ~~recognized~~and inventory in ~~other~~transit, ~~comprehensive income until~~ the ~~underlying~~Partnership ~~hedged~~as ~~item~~of isMarch 31, ~~recognized~~2011 ~~in earnings~~had 29.4 million ~~The Partnership~~gallons ~~has~~of ~~elected~~future ~~not~~contracts to ~~designate~~buy ~~its~~heating ~~derivative~~oil; ~~instruments~~33.6 million asgallons ~~hedging~~of ~~instruments~~future ~~under~~contracts ~~this~~to ~~standard~~sell ~~and~~heating ~~the~~oil; ~~change~~and in3.2 million ~~fair~~gallons ~~value~~ of ~~the~~swap ~~derivative~~contracts ~~instruments~~to issell ~~recognized~~heating inoil. ~~our~~To ~~statement~~hedge a portion of ~~operations~~its ininternal fuel usage, the ~~line~~Partnership ~~item~~as ~~(increase) decrease~~of inMarch 31, ~~the~~2011, ~~fair~~had ~~value~~0.6 million gallons of ~~derivative~~swap ~~instruments.~~contracts ~~Realized~~to ~~gains~~buy gasoline; and ~~losses~~0.4 million ~~are~~gallons ~~recorded~~of inswap ~~cost~~contracts and 0.5 million gallons of ~~product~~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 31, 2010, the Partnership had 0.6 million gallons of swap contracts to buy heating oil; 43.0 million gallons of call options; 0.2 million gallons of put options and 9.2 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 31, 2010 had 23.0 million gallons of future contracts to buy heating oil; 33.6 million gallons of future contracts to sell heating oil; and 11.3 million gallons of swap contracts to sell heating oil. To hedge a portion of its internal fuel usage, the Partnership as of March 31, 2010, had 0.6 million gallons of swap contracts to buy gasoline and 1.2 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 31, 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 31, 2011, $0.1 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 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 HedgingInstruments Under FASB ASC 815-10	Balance Sheet Location	Total			Quoted Prices inActive Markets forIdentical AssetsLevel 1			Significant OtherObservable InputsLevel 2			SignificantUnobservableInputs Level 3
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
Asset Derivatives at December 31, 2010
Asset Derivatives at March 31, 2011
Commodity contracts	Fair asset and fair liability value of derivative instruments	$	2140,~~030~~341		$	113,~~691~~281		$	1927,~~339~~060		$	—
Commodity contracts	Long-term derivative assets netted with long-term derivative liabilities, included in other long-term liabilities		~~165~~64			~~129~~39			3625
Commodity contract assets at December 31, 2010		$	21,195		$	1,820		$	19,375		$	—
Commodity contract assets at March 31, 2011		$	40,405		$	13,320		$	27,085		$	—
Liability Derivatives at December 31, 2010
Liability Derivatives at March 31, 2011
Commodity contracts	Fair liability and fair asset value of derivative instruments	$	(214,~~938~~077	)	$	(113,~~519~~322	)	$	(~~1,419~~755	)	$	—
Commodity contracts	Long-term derivative liabilities included in other long-term liabilities		(~~483)~~220	)		(~~483)~~209	)		(11	)		—
Commodity contract liabilities at December 31, 2010		$	(3,421	)	$	(2,002	)	$	(1,419	)	$	—
Commodity contract liabilities at March 31, 2011		$	(14,297	)	$	(13,531	)	$	(766	)	$	—
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
Derivatives Not Designated as Hedging Instruments Under FASB ASC 815-10	Location of (Gain) or LossRecognized in Income on Derivative	Three MonthsEnded December 31,2010			Three MonthsEnded December 31,2009
Derivatives Not Designatedas Hedging InstrumentsUnder FASB ASC 815-10	Location of (Gain) or LossRecognized in Income onDerivative	Three MonthsEnded March 31,2011			Three MonthsEnded March 31,2010			Six MonthsEnded March 31,2011			Six MonthsEnded March 31,2010
Commodity contracts	Cost of product (a)	$	9(5,~~546~~870	)	$	911,~~878~~618		$	4,205		$	21,877
Commodity contracts	~~(Increase)~~Cost /of ~~decrease~~installations inand ~~the~~service ~~fair value of derivative instruments~~(a)	$	(~~13,906~~321	)	$	(~~3,392~~297	)	$	(414	)	$	(518	)
Commodity contracts	Delivery and branch expenses (a)	$	(380	)	$	(195	)	$	(483	)	$	(355	)
Commodity contracts	(Increase) / decrease in the fair value of derivative instruments	$	(13,261	)	$	(4,702	)	$	(27,167	)	$	(8,094	)

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

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)	~~December~~March 31,~~2010~~2011		September 30,2010
Property and equipment	$	~~148~~149,~~533~~498	$	146,494
Less: accumulated depreciation		~~103~~105,~~455~~005		101,782
Property and equipment, net	$	4544,~~078~~493	$	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 ~~December~~March 31, ~~2010~~2011, comprehensive income was $2149.01 million, comprised of net income of $2048.67 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 ~~December~~March 31, ~~2009~~2010, comprehensive income was $1240.49 million, comprised of net income of $1240.05 million, an unrealized gain on pension plan obligation of $0.6 million and the tax affect of $0.2 million.

For the six months ended March 31, 2011, comprehensive income was $70.0 million, comprised of net income of $69.2 million, an unrealized gain on pension plan obligation of $1.4 million and the tax effect of $0.6 million. For the six months ended March 31, 2010, comprehensive income was $53.3 million, comprised of net income of $52.6 million, an unrealized gain on pension plan obligation of $1.2 million and the tax affect of $0.5 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 months ended ~~December~~March 31, ~~2010~~2011, and ~~2009~~ 2010 are as follows:

	Three Months EndedDecember 31,
	Three Months EndedMarch 31,				Six Months EndedMarch 31,
(in thousands)	~~2010~~2011		~~2009~~2010		2011		2010
Income before income taxes	$	3784,~~569~~149	$	2270,~~082~~371	$	121,718	$	92,453
Current tax expense	$	212,~~031~~590	$	~~849~~3,277	$	14,621	$	4,126
Deferred tax expense		1422,~~980~~878		926,~~228~~559		37,858		35,787
Total tax expense	$	1735,~~011~~468	$	1029,~~077~~836	$	52,479	$	39,913

As of the calendar tax year ended December 31, 2010, Star Acquisitions, a wholly-owned subsidiary of the Partnership, had aan estimated Federal net operating loss carry forward (“NOL”) of approximately $16.4 million of which $7.3 million is related to the acquisition of Champion Energy Corporation. The Federal NOLs, which will expire between 2018 and 2024, are generally available to offset any future taxable income. In general, the Partnership would be deemed to have an “ownership change” under Section 382 if , immediately after any owner shift involving a 5% unitholder or any equity structure shift, the percentage of units of the Partnership owned by one or more 5% unitholder has increased by more than 50% over the lowest percentage of units of the Partnership (or any predecessor entity) owned by such unitholder at any time during the three-year testing period.

In June 2007, the Partnership amended its Amended and Restated Unit Purchase Rights Agreement dated as of July 20, 2006 in order to protect the Partnership’s NOLs for Federal income tax purposes by adding provisions which would have the effect of deterring any person or group from acquiring more than 5% (reduced from 15% prior to the amendment) of the Partnership’s issued and outstanding common units. The amendment also discouraged existing 5% or greater unitholders

~~(including~~are ~~the~~generally ~~General~~available ~~Partner) from acquiring additional common units equal~~ to 1%offset orany ~~more~~future oftaxable ~~the~~income ~~outstanding~~but ~~common~~are ~~units.~~also ~~A person or group that acquires units in excess of these amounts would be~~ subject to ~~substantial~~annual ~~dilution~~limitations ~~under~~on the ~~Rights~~amount ~~Agreement.~~that Incan ~~May~~be 2009, the Partnership entered into a further amendment to its Amended and Restated Unit Purchase Rights Agreement to amend the definition of acquiring person to restore the acquisition threshold to 15% of the outstanding common unitsused. ~~The Amended and Restated Unit Purchase Rights Agreement expires on April 16, 2011.~~

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 ~~December~~ March 31, ~~2010~~2011, we had unrecognized income tax benefits totaling $2.4 million including related accrued interest and penalties of $0.23 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 ~~December~~ March 31, 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.

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	) (a)
Balance as of December 31, 2010	$	199,052
Balance as of March 31, 2011	$	198,845

(a) As provided for by FASB ASC 805 Accounting for Business Combinations and Noncontrolling Interests, 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 31, 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:

	December 31, 2010						September 30, 2010
	Gross						Gross
	Carrying		Accum.				Carrying		Accum.
(in thousands)	Amount		Amortization		Net		Amount		Amortization		Net
Customer lists and other intangibles	$	252,655	$	196,272	$	56,383	$	252,385	$	193,491	$	58,894

AmortizationTable expenseof for intangible assets was $2.8 million for the three months ended December 31, 2010 compared to $2.1 million for the three months ended December 31, 2009. 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): Contents

	Estimated Annual BookAmortization Expense
	March 31, 2011						September 30, 2010
2011	$	10,260
(in thousands)	GrossCarryingAmount		Accum.Amortization		Net		GrossCarryingAmount		Accum.Amortization		Net
2012	$	5,897
Customer lists and other intangibles	$	252,778	$	198,957	$	53,821	$	252,385	$	193,491	$	58,894
2013	$	5,895
2014	$	5,819
2015	$	5,684

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 Book Amortization Expense
2011	$	10,264
2012	$	5,914
2013	$	5,912
2014	$	5,837
2015	$	5,701

5) Business Combinations

On December 16, 2010 the Partnership acquired a heating oil and propane dealer for $1.6 million in cash, and on February 9, 2011 the Partnership acquired a heating oil dealer for $0.2 million in cash. The operating results of ~~this~~these ~~acquisition~~two 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 comprised primarily of intangibles, certain working capital items, and are reflected in the Consolidated Balance Sheet as of ~~December~~March 31, ~~2010~~2011.

6) Long-Term Debt and Bank Facility Borrowings

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

	At December 31, 2010				At September 30, 2010
	At March 31, 2011				At September 30, 2010
	Carrying		Estimated		Carrying		Estimated
	CarryingAmount		EstimatedFair Value (a)		CarryingAmount		EstimatedFair Value (a)
	Amount		Fair Value (a)		Amount		Fair Value (a)
8.875% Senior Notes (b)	$	124,219	$	128,750	$	—	$	—
8.875% Senior Notes (b)	$	124,198	$	125,938	$	—	$	—
10.25% Senior Notes (c)		—		—		82,770		83,908
Revolving Credit Facility Borrowings (d)		1331,~~076~~593		1331,~~076~~593		—		—
Total debt	$	~~137~~155,~~274~~812	$	~~139~~160,~~014~~343	$	82,770	$	83,908
Total long-term portion of debt	$	124,~~198~~219	$	~~125~~128,~~938~~750	$	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 ~~these~~$125.0 ~~notes~~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 31, 2011. Under the terms of the indenture, these notes permit restricted payments of $22 million, permit the Partnership to incur debt up to $100 million for acquisitions without passing certain financial tests, and restrict the proceeds of asset sales from being invested in current assets for purposes of the “asset sale” covenant.

(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.

1 of each year. The discount on these notes included above was $0.8 million at December 31, 2010. Under the terms of the indenture, these notes permit restricted payments of $22 million, permit the Partnership to incur debt up to $100 million for acquisitions without passing certain financial tests, and restrict the proceeds of asset sales from being invested in current assets for purposes of the “asset sale” covenant.

In January 2011, an exchange offer of the Private Notes for substantially identical public notes registered with the Securities and Exchange Commission was issued. Unless extended, the exchange offer expires on February 16, 2011.

(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 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, that extends to July 2012, 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 this facility. The Partnership can increase the facility size by $50 million without the consent of the bank group. The bank group is not obligated to fund the $50 million increase. If the bank group elects not to fund the increase, the Partnership can add additional lenders to the group, with the consent of the Agent, which shall not be unreasonably withheld. The interest rate is LIBOR plus (i) 3.50% (if availability, as defined in the revolving credit facility agreement is greater than or equal to $150 million), or (ii) 3.75% (if availability is greater than $75 million but less than $150 million), or (iii) 4.00% (if availability is less than or equal to $75 million). The commitment fee on the unused portion of the facility is 0.75% per annum.

In January 2010, the Partnership entered into a first amendment to the amended and restated asset based revolving credit facility agreement that updated the consolidated fixed charges defined term.

At ~~December~~March 31, ~~2010~~2011, $1331.1 6 million was outstanding under the revolving credit facility and $4246.7 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 ~~December~~March 31, ~~2010~~2011, availability was $~~155~~181.15 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 EndedDecember 31,
	Three Months EndedMarch 31,						Six Months EndedMarch 31,
(in thousands)	~~2010~~2011			~~2009~~2010			2011			2010
Components of net periodic benefit cost:
Service cost	$	—		$	—		$	—		$	—
Interest cost		748			~~811~~812			1,496			1,623
Expected return on plan assets		(879	)		(~~665~~667	)		(1,758	)		(1,332	)
Net amortization		691			616			1,382			1,232
Net periodic benefit cost	$	560		$	~~762~~761		$	1,120		$	1,523

~~During~~For the ~~three~~six months ended ~~December~~March 31, ~~2010~~2011, the Partnership contributed $01.62 million and expects to make an additional $2.61 million contribution in fiscal 2011 to fund its pension obligation.

8) Supplemental Disclosure of Cash Flow Information

	Three Months EndedDecember 31,
	Six Months EndedMarch 31,
(in thousands)	~~2010~~2011			~~2009~~2010
Cash paid during the period for:
Income taxes, net	$	~~117~~2,263		$	~~634~~641
Interest	$	35,~~829~~130		$	~~825~~8,697
Debt extinguishment costs	$	1,409		$	—
Debt redemption premium	$	1,409		$	854
Non-cash financing activities:
Decrease in interest expense—amortization of net debt premium 10.25% and debt discount 8.875%	$	(13	)	$	40
Increase (decrease) in interest expense—amortization of net debt premium 10.25% and debt discount 8.875%	$	9		$	(74	)
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

Offer to Exchange $125.0 Million 8.875% Senior Notes due 2017

On January 12, 2011, an exchange offer of the Partnership’s currently outstanding $125.0 million private 8.875% Senior Notes due 2017 for substantially identical public notes registered with the Securities and Exchange Commission was issued. Unless extended, the exchange offer expires on February 16, 2011.

Quarterly Distribution Declared

On ~~January~~April 2514, 2011, the Partnership declared a quarterly distribution of $0.0775 per common unit, payable on ~~February~~May 1413, 2011, to holders of record on ~~February~~May 45, 2011.

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 ~~10-K~~10K 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 induring the last five years in the sale of approximately 30% of our volume of ~~home~~ 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~~ 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.

~~Weather~~Impact ~~Hedge~~on ~~Contract~~Operating ~~Warm~~Results ~~Weather~~of Increasing Wholesale Product Costs

~~Weather~~During ~~conditions~~the ~~have~~heating aseason ~~significant~~of ~~impact~~fiscal on2011 ~~the~~wholesale ~~demand~~product ~~for~~costs ~~home~~continued ~~heating~~to ~~oil~~escalate, ~~and~~which ~~propane~~limited ~~because~~Star’s ~~our~~ability to maintain/expand margins for variable and ceiling priced customers. ~~depend~~Conversely, onduring ~~this~~certain ~~product principally~~peak ~~for~~months of the heating ~~purposes.~~seasons ~~Actual~~for ~~weather~~fiscal ~~conditions~~2010 ~~can~~and ~~vary~~2009, ~~substantially~~wholesale ~~from~~product ~~year~~costs declined, which contributed to ~~year~~the Partnership’s ability to expand its per gallon margins during these periods, ~~significantly~~as ~~affecting~~wholesale prices decreased more rapidly than our ~~financial~~retail ~~performance~~prices. ToFor ~~partially~~example, ~~mitigate~~over 90% of our ceiling customer reached their maximum contract price during the ~~adverse~~three ~~effect~~months ofended ~~warm~~March 31, 2011, ~~weather~~as oncompared ~~our~~to ~~cash~~the ~~flows~~three months ended March 31, we2010 ~~have~~when ~~entered~~70% ~~into a~~of ~~weather~~our ~~hedge~~ceiling ~~contract~~customers ~~with~~reached ~~Renaissance~~their ~~Trading~~maximum ~~Ltd~~contract price. ~~Under~~During the ~~weather~~three ~~hedge~~months ~~contract~~ended weMarch 31, ~~will~~2009, ~~receive~~less athan ~~payment~~1% of ~~$35~~our ceiling customers reached their maximum contract price. If wholesale product costs continue to escalate,~~000~~ the Partnership’s ability to maintain and/or expand per ~~heating~~gallon ~~degree-day~~margins could be greatly diminished and profitability measures would be adversely impacted. As retail prices continue to rise, ~~when~~gross ~~the~~customer ~~total~~losses ~~number~~could ofincrease ~~heating~~and ~~degree-days~~Star’s inability ~~the~~to ~~period~~attract ~~covered~~new iscustomers ~~less~~might ~~than~~decrease, 92which could result in an increase in net customer attrition.5% ofThe recent increase in the ~~10-year~~cost of home heating oil and petroleum ~~average.~~products ~~The~~in ~~hedge~~general ~~covers~~has also resulted in an increase in certain operating expenses that are directly tied to the ~~period~~underlying ~~from~~cost ~~November 1~~of product such as bad debt expense, ~~2010~~credit ~~through~~card ~~March 31~~processing costs, ~~2011~~vehicle ~~taken~~fuels and other transportation expenses. In addition, interest expense may rise further as athe ~~whole~~Partnership ~~and~~is ~~has~~required to finance a ~~maximum~~higher ~~payout~~level of ~~$12.5~~accounts ~~million~~receivable and inventory.

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. 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 margins. In addition, should actual usage in any 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 home heating oil and propane 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.

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. ~~Like~~As ~~any other market~~ 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) to April 30, 2011

Impact on Liquidity of Wholesale Product Cost Volatility

	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 (a)		2.49		2.75		1.89		2.20		1.13		1.63		2.42		3.15
June 30						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

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.

~~(a)~~Impact toof ~~January~~Warm ~~31,~~Weather ~~2011~~on Operating Results; Weather Hedge Contract

~~The wholesale~~Weather ~~price~~conditions ofhave a significant impact on the demand for home heating oil ~~has~~and ~~been~~propane ~~extremely~~because ~~volatile~~our ~~over~~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 ~~last~~adverse ~~several~~effect of warm weather on our cash flows, we have used weather insurance and weather hedging contracts for a number of years. ~~Our~~For ~~liquidity~~the isfiscal ~~adversely~~2011 ~~impacted~~heating inseason, ~~times~~we entered into a weather hedge contract with Renaissance Trading Ltd. under which we were entitled to receive a payment of ~~increasing~~$35,000 per heating degree-day, ~~oil~~when ~~prices~~the total number of heating degree-days in the period covered was less than 92.5% of the 10-year average. The hedge covered the period from November 1, 2010 through March 31, 2011 taken as wea ~~must~~whole ~~use~~and ~~cash~~had toa ~~pay~~maximum ~~for~~payout of ~~our~~$12.5 ~~hedging~~million. ~~requirements~~The ~~and~~heating todegree 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.

~~fund~~Per aGallon ~~portion~~Gross ofProfit ~~the~~Margins 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.

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. 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.

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 ~~will be~~were $916.14 million, ~~excluding~~(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 the next twelve 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.

8.875% Senior Note Offering

In November 2010, we issued $125.0 million of Senior Notes due 2017. The notes will 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 10.25% Senior Notes due 2013, with the remainder available for general partnership purposes.

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 fiscal year.

Estimated Depreciation and Amortization Expense

Fiscal Year	Book		Tax
2011	$	20,~~314~~349	$	31,~~215~~532
2012		14,~~294~~214		2728,~~935~~285
2013		11,~~083~~151		24,~~536~~899
2014		9,~~644~~918		2120,~~071~~887
2015		89,~~749~~027		1817,~~258~~895

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:

•

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 months of fiscal 2011, the Partnership ~~has thus far~~ completed ~~one~~two ~~acquisition~~acquisitions and added approximately 1,~~500~~900 home heating oil and propane accounts. ~~From~~During ~~April 1 to September 30, 2010 (after the~~ fiscal 2010 ~~heating season)~~, the Partnership completed five acquisitions and added approximately 56,100 home heating oil, propane and security accounts. While these later acquisitions provided additional revenues in fiscal 2010, the Partnership’s profitability measures such as operating income and net income were adversely impacted as the associated product costs and operating expenses ~~from~~exceeded ~~these~~revenues, reflecting the fact that acquisitions ~~exceeded~~were ~~revenues,~~all ~~which~~completed isafter ~~normal~~the ~~for~~end ~~this~~of ~~non-~~the fiscal 2010 heating ~~period~~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 ~~included~~counted inas ~~the calculation of~~ gross customer gains. ~~Marketing~~However the impact of marketing activity ~~for~~on ~~our~~acquired ~~acquisitions~~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 Customer Gains, Gross Customer Losses and Net Customer Attrition:

Three Months Ended December 31,
		Fiscal Year Ended
2010												2009 (a)												2008 (a)
		2011												2010 (a)												2009 (a)
~~Gross Customer~~		Gross Customer						~~NetAttrition~~		NetAttrition		~~Gross Customer~~		Gross Customer						~~NetAttrition~~		NetAttrition		~~Gross Customer~~		Gross Customer						~~NetAttrition~~		NetAttrition
~~Gains~~		Gains		~~Losses~~		Losses						~~Gains~~		Gains		~~Losses~~		Losses						~~Gains~~		Gains		~~Losses~~		Losses
	21,900				24,100				(2,200	)			19,000				21,600				(2,600	)			26,300				31,800				(5,500	)
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 Gains, Gross Customer Losses and Net Customer Attrition as a Percentage of the Customer Base:

Three Months Ended December 31,
		Fiscal Year Ended
2010												2009 (a)												2008 (a)
		2011												2010 (a)												2009 (a)
~~Gross Customer~~		Gross Customer						~~NetAttrition~~		NetAttrition		~~Gross Customer~~		Gross Customer						~~NetAttrition~~		NetAttrition		~~Gross Customer~~		Gross Customer						~~NetAttrition~~		NetAttrition
~~Gains~~		Gains		~~Losses~~		Losses						~~Gains~~		Gains		~~Losses~~		Losses						~~Gains~~		Gains		~~Losses~~		Losses
	5.3	%			5.8	%			(0.5	%)			5.1	%			5.8	%			(0.7	%)			6.5	%			7.9	%			(1.4	%)
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	%)
			8.1	%			9.9	%			(1.8	%)			8.1	%			9.6	%			(1.5	%)			9.4	%			13.9	%			(4.5	%)

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

During the first ~~quarter~~six months of fiscal 2011, we lost 27,~~200~~600 accounts (net), or 01.58% of our home heating oil and propane customer base, as ~~slightly~~compared ~~less~~to ~~than~~ our loss of 25,~~600~~800 accounts (net), or 01.75% of our home heating oil customer base during the first ~~quarter~~six months of fiscal 2010. ~~Net~~The ofincrease ~~attrition~~in the ~~Partnership’s~~absolute ~~customer~~number ~~base~~of ~~increased by approximately 11.0% year-over-year due to acquisitions. For the three months ended December 31, 2010,~~ gross ~~gains~~customer ~~and gross~~ losses ~~increased~~of ~~by 15.3% and 11.6%~~5,400 ~~respectively,~~accounts ~~versus~~was ~~the~~largely ~~prior year period,~~ due ~~in part~~ to ~~the~~losses associated ~~increase~~with increases in ~~size~~the price of ~~the~~home ~~Partnership’s~~heating ~~customer base~~oil.

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 months ended March 31, 2011, gross gains and gross losses increased by 12.0% and 15.1%, respectively, as compared to the prior year period, due in part to the 10.9% increase in size of the Partnership’s customer base.

During the six months ended March 31, 2011, we lost 0.7% of our accounts to natural gas which compares to losses to natural gas of 0.6% for the six months ended March 31, 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.

~~Three~~Price-Protected ~~Months~~Customer ~~Ended~~Renewals ~~December 31, 2010~~

~~Compared~~Approximately 72% of the Partnership’s price-protected customers have agreements with us that are subject to annual renewal in the period ~~Three~~from ~~Months~~April ~~Ended~~through ~~December~~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 3129, ~~2009~~2011, the wholesale cost of home heating oil as measured by the NYMEX was $3.26 and approximately $0.97 higher than at April 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.

Three Months Ended March 31, 2011

Compared to the Three Months Ended March 31, 2010

Volume

For the three months ended ~~December~~March 31, ~~2010~~2011, retail volume of home heating oil and propane increased by 1621.72 million gallons, or 1713.45%, to ~~112~~178.79 million gallons, as compared to 96157.07 million gallons for the three months ended ~~December~~March 31, ~~2009~~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
Volume - Three months ended December 31, 2009		96.0
Volume - Three months ended March 31, 2010		157.7
Impact of colder temperatures		5.3
Acquisitions		22.1
Acquisitions		13.2
Impact of colder temperatures		12.9
Net customer attrition		(48.64	)
Other		2.8
Lower Margin COD/BID and Commercial Volume		(1.3	)
Change		16.7
Conservation and Other		(4.1	)
Volume - Three months ended December 31, 2010		112.7
Change		21.2
Volume - Three months ended March 31, 2011		178.9

~~Temperatures~~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 ~~December~~March 31, ~~2010~~2011 were 5 8.47% colder than the three months ended ~~December~~March 31, ~~2009~~2010 and approximately 21.4% colder than normal, as reported by the National Oceanic Atmospheric Administration (“NOAA”). ~~From~~Between ~~January~~April 1, 2010 toand ~~December~~March 31, ~~2010~~2011, net customer attrition was ~~approximately 4~~5.94%, 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~~were 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.

~~The~~Volume ~~percentage~~ of ~~heating~~other ~~oil~~petroleum ~~and~~products ~~propane volume sold to residential variable price customers increased to 44.7%~~ for the three months ended ~~December~~March 31, ~~2010,~~2011 ~~compared~~increased toby 413.~~6% for the three months ended December~~2 31million gallons, ~~2009.~~or ~~The percentage of heating oil and propane volume sold to residential price-protected customers decreased to 42~~30.68% ~~for the three months ended December 31~~, ~~2010, compared~~ to 44 13.~~2% for the three months ended December~~8 ~~31,~~million ~~2009. For the three months ended December 31~~gallons, ~~2010,~~as ~~sales~~compared to ~~commercial/industrial~~ ~~customers decreased to 12~~10.8%5 million gallons of ~~total~~other ~~heating~~petroleum ~~oil~~products ~~and~~sold ~~propane~~during ~~volume sales, compared to 14.2% for~~ the three months ended ~~December~~March 31, ~~2009~~2010. ~~Generally,~~This ~~the~~increase ~~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~~additional ~~renewal~~volume ~~season~~provided ~~preceding~~from ~~fiscal 2011 than during the comparable renewal period preceding fiscal 2010~~acquisitions.

~~Volume~~The percentage of ~~other~~heating ~~petroleum~~oil ~~products~~volume sold to residential variable price customers increased to 44.1% for the three months ended ~~December~~ March 31, ~~2010~~2011, ~~increased~~as ~~by 2.3 million~~compared ~~gallons,~~to ~~or 25~~42.06% for the three months ended March 31, 2010. The percentage of heating oil volume sold to 11residential price-protected customers decreased to 43.5% for the three months ended March ~~million~~31, ~~gallons~~2011, as compared to 944.2% for the three months ended March ~~million~~31, ~~gallons~~2010. For the three months ended March 31, 2011, sales to commercial/industrial customers decreased to 12.4% of ~~other~~total ~~petroleum~~heating ~~products~~oil ~~sold~~volume ~~during~~sales, as compared to 13.2% for the three months ended ~~December~~March 31, ~~2009~~2010. ~~The~~Generally, ~~increase~~the shift to variable pricing was largely due to ~~the~~our ~~additional~~customers’ ~~volume~~reluctance to “lock in” or “cap” their prices, as home heating oil and propane prices for our price-protected ~~provided~~offerings ~~from~~were ~~acquisitions~~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 ~~December~~March 31, ~~2010~~2011, product sales increased $~~103~~175.28 million, or 34.24%, to $~~405~~686.05 million, as compared to $~~301~~510.87 million for the three months ended ~~December~~March 31, ~~2009~~2010, due to the previously described increases in sales volume of 14.6% and higher product selling prices in response to an increase in ~~the~~ wholesale product ~~costs~~cost.

Installation and Service Sales

For the three months ended ~~December~~March 31, ~~2010~~2011, service and installation sales increased $74.54 million, or 1510.97%, to $5445.5 4 million, as compared to $4741.10 million for the three months ended ~~December~~March 31, ~~2009~~ 2010, largely due to ~~the~~ additional ~~revenues~~revenue from acquisitions of $65.10 million. For our base business, installation revenue declined by $0.8 million, or 5.8% , largely due to the

2425

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 ~~December~~March 31, ~~2010~~2011, cost of product increased $87157.25 million, or 4043.65%, to $~~301~~519.72 million, as compared to $~~214~~361.57 million for the three months ended ~~December~~March 31, ~~2009~~2010, due to to increases in volume sales of ~~home~~14.6% ~~heating oil~~ and ~~propane and other petroleum products sold and~~ higher per gallon product costs of 25.3%.

Gross Profit—Product

The table below calculates the Partnership’s per gallon margins and reconciles product gross profit for home heating oil and propane and other petroleum products. We believe the change in home heating oil ~~and propane~~ margins should be evaluated before the effects of increases or decreases in the fair value of derivative instruments, as we believe that realized per gallon margins should not include the impact of non-cash changes in the market value of hedges before the settlement of the underlying transaction. On that basis, home heating oil and propane margins for the three months ended ~~December~~March 31, ~~2010~~2011 ~~increased~~decreased by $0.~~0079~~0122 per gallon, or 01.93%, to $0.~~8925~~9177 per gallon, from $0.~~8846~~9299 per gallon in the three months ended ~~December~~March 31, ~~2009~~2010. Our fiscal 2010 and fiscal 2011 acquisitions have 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~~ declined $0.~~0176~~0036 per gallon, or 2.0.4%. Product sales and cost of product include home heating oil and propane, and other petroleum products.

	Three Months Ended
	December 31, 2010				December 31, 2009
(in millions except per gallon amounts)	Amount(000)		PerGallon		Amount(000)		PerGallon
Home Heating Oil/Propane
Volume (in millions of gallons)		112,663				95,984
Sales	$	373,798	$	3.3178	$	280,818	$	2.9257
Cost		273,247		2.4253		195,915		2.0411
Gross Profit	$	100,551	$	0.8925	$	84,903	$	0.8846
	Amount(000)		PerGallon		Amount(000)		PerGallon
Other Petroleum Products
Volume (in millions of gallons)		11,531				9,223
Sales	$	31,170	$	2.7031	$	20,947	$	2.2712
Cost		28,425		2.4651		18,600		2.0166
Gross Profit	$	2,745	$	0.2381	$	2,347	$	0.2546
	Amount(000)				Amount(000)		Change
Total Product
Sales	$	404,968			$	301,765	$	103,203
Cost		301,672			$	214,515		87,157
Gross Profit	$	103,296			$	87,250	$	16,046

During the heating season of fiscal 2011, home heating oil costs continued to escalate, 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 ability to expand its home heating oil margins that year, as wholesale prices decreased more rapidly than our retail prices. Over 90% of our ceiling customer 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. If the wholesale product costs continues 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~~26 the three months ended December 31, 2010, total product gross profit increased by $16.0 million to $103.3 million, compared to $87.3 million for the three months ended December 31, 2009, due to the impact of higher home heating oil and propane volume ($15.6 million), higher home heating oil and propane margins ($0.9 million) and the additional gross profit from other petroleum products sold ($0.4 million).

(Increase) / Decrease in the Fair Value of Derivative Instruments

During the three months ended December 31, 2010, the increase in the fair value of derivative instruments resulted in the recording of a $13.9 million credit due to the expiration of certain hedged positions or their realization to cost of product (a $4.0 million credit) and an increase in the market value for unexpired hedges (a $9.9 million credit).

During the three months ended December 31, 2009, the increase in the fair value of derivative instruments resulted in the recording of a $3.4 million credit due to the expiration of certain hedged positions or their realization to cost of product (a $3.5 million credit) and a decrease in the market value for unexpired hedges (a $0.1 million charge).


	Three Months Ended
	March 31, 2011				March 31, 2010
	Amount (000)		Per Gallon		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)		Per Gallon		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

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).

(Increase) Decrease in the Fair Value of Derivative Instruments

During the three months ended March 31, 2011, the increase in the fair value of derivative instruments resulted in the recording of a $13.3 million net credit due to the expiration of certain hedged positions or their realization to cost of product (a $5.5 million charge), and an increase in the market value for unexpired hedges (a $18.8 million credit).

During the three months ended March 31, 2010, the increase in the fair value of derivative instruments resulted in the recording of a $4.7 million net credit due to the expiration of certain hedged positions or their realization to cost of product (a $4.8 million credit) and a decrease in the market value for unexpired hedges (a $0.1 million charge).

Cost of Installations and Service

During the three months ended ~~December~~March 31, ~~2010~~2011, cost of installations and service increased $63.96 million, or 158.24%, to $5246.61 million, as compared to $4542.75 million for the three months ended ~~December~~March 31, ~~2009~~2010, ~~due~~as ~~primarily to~~ an estimated $54.25 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 ~~overhead~~administrative functions and direct expenses such as service technician time cannot be precisely allocated and generally remain in service costs.

Installation costs increased by $3.1.2 million to $1812.5 million, or 8290.80% of installation sales, during the three months ended ~~December~~March 31, ~~2010~~2011, versus $1511.43 million, or 8387.60% of installation sales during the three months ended ~~December~~March 31, ~~2009~~2010. The increase in installation costs was largely due to acquisitions ($21.3 5 million) ~~and higher heating equipment sales in the base business~~. Service expenses increased by $32.84 million to $3433.1 6 million, or 106.05% of service sales, during the three months ended ~~December~~March 31, ~~2010~~2011, from $3031.3 million in the three months ended ~~December~~March 31, ~~2009~~2010, or ~~105~~111.74% of sales. The increase in service costs was again largely due to acquisitions ($23.9 0 million) ~~and additional costs associated with 5~~.4% ~~colder temperatures.~~ For the three months ended ~~December~~March 31, ~~2010~~2011, a ~~net~~combined ~~gross~~loss ~~profit~~ from service and installation of $10.97 million was generated, compared to a ~~net~~combined ~~gross~~loss ~~profit~~ of $1.45 million for the three months ended ~~December~~March 31, ~~2009~~2010.

Delivery and Branch Expenses

For the three months ended ~~December~~March 31, ~~2010~~2011, delivery and branch expenses increased $914.21 million, or 1620.18%, to $6682.0 million, compared to $5667.89 million for the three months ended ~~December~~March 31, ~~2009~~2010. Acquisitions added $78.43 million in delivery and branch ~~expenses,~~expense. ~~while~~In in the base business, delivery and branch expenses increased by $15.8 million largely due to higher delivery ~~expenses~~costs of $1.8 million associated with the increase in volume and ~~a major~~ numerous snow ~~storm~~storms experienced in ~~December~~the ~~2010~~second quarter of fiscal 2011, higher bad debt expense and credit card fees of $1.9 million due to the increase in sales of 32.6% and greater insurance claims expense of $2.0 million due in part to the extreme winter weather conditions.

Depreciation and Amortization

For the three months ended ~~December~~March 31, ~~2010~~2011, depreciation and amortization expenses increased by $1.1 million, or 2932.50%, to $4.67 million, as compared to $3.56 million for the three months ended ~~December~~ March 31, ~~2009~~2010.

~~Amortization~~Depreciation expense was higher by $0.5 million due primarily to additional depreciation expense from depreciable property and equipment of fiscal 2010 acquisitions. Amortization expense was higher by $0.76 million as the additional amortization expense from fiscal 2010 and 2011 acquisitions of $1.01 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 ~~in fiscal 2010~~.

General and Administrative Expenses

For the three months ended ~~December~~March 31, ~~2010~~2011, general and administrative expenses ~~were~~decreased $40.93 million, ~~slightly~~to ~~less~~$5.3 ~~when~~million, ~~compared~~from to $5.16 million for the three months ended ~~December~~March 31, ~~2009~~2010, primarily due to lower professional fees and lower pension expense relating to the Partnership’s frozen defined benefit pension plan.

Operating Income (Loss)

For the three months ended ~~December~~March 31, ~~2010~~2011, operating income increased $1712.18 million to $4387.79 million, from ~~compared to~~ $2675.61 million for the three months ended ~~December~~March 31, ~~2009~~2010, as an increase in product gross profit of $1618.3 million, an improvement in net service and installation of $0.8 million, and a favorable change in the fair value of derivative instruments of $108.56 million was reduced by higher ~~delivery~~operating ~~and~~expense ~~branch~~increases ~~expenses~~(including depreciation and amortization) of $914.2 9 million.

Interest Expense

For the three months ended ~~December~~March 31, ~~2010~~2011, interest expense ~~decreased~~increased ~~slightly~~by $0.4 million, or 11.2% to $4.23 million as compared to $4.3.9 million for the three months ended ~~December~~March 31, ~~2009~~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 $15.1 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 largely unchanged.

During the three months ended March 31, 2011, the Partnership borrowed on average $56.8 million under its bank credit facility or $47.6 million more than the three months ended March 31, 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 ~~December~~March 31, ~~2010~~2011, interest income increased $0.13 million, or 3532.27%, to $01.52 million, as compared to $0.49 million for the three months ended ~~December~~March 31, ~~2009~~2010, due to higher finance charge income from acquisitions.

Amortization of Debt Issuance Costs

For the three months ended ~~December~~ March 31, ~~2010~~2011, amortization of debt issuance costs was unchanged at $0.7 million, when compared to the three months ended ~~December~~March 31, ~~2009~~2010.

~~Loss~~28 ~~on Debt Repurchase~~

DuringTable the first quarter of fiscal 2011, the Partnership repurchased $82.5 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 $1.7 million for this transaction. Contents

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 ~~December~~March 31, ~~2010 income~~2011 income tax expense increased $65.97 million, to $1735.0 5 million, from $1029.18 million for the three months ended ~~December~~March 31, ~~2009~~2010. The increase in income tax expense was mainly due to the higher ~~level of~~ pretax income of $1513.58 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 ~~December~~March 31, ~~2010~~2011, the Partnership generated net income of $2048.6 7 million, compared to $1240.05 million for the three months ended ~~December~~March 31, ~~2009~~2010, as the ~~$17.1~~increase ~~million~~in ~~of increased~~ operating income ~~was~~of ~~offset by the~~ $112.78 million ~~loss~~was onpartially ~~redemption~~offset ofby ~~debt~~an ~~and~~increase ~~increased~~in income tax expense of $65.97 million.

Adjusted EBITDA

For the three months ended ~~December~~March 31, ~~2010~~2011, Adjusted EBITDA increased by $75.64 million, or 287.3%, to $3479.34 million as the impact of colder temperatures of 58.47% and ~~the~~ $411.97 million of Adjusted EBITDA provided by fiscal 2010 and 2011 acquisitions was ~~reduced~~ somewhat offset by net customer attrition in the base business, higher delivery and branch expenses attributable largely 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.

	Three Months EndedDecember 31,
	Three Months EndedMarch 31,
(in thousands)	~~2010~~2011			~~2009~~2010
Net income	$	2048,~~558~~681		$	1240,~~005~~535
Plus:
Income tax expense		1735,~~011~~468			1029,~~077~~836
Amortization of debt issuance cost		~~694~~732			~~656~~672
Interest expense, net		3,~~688~~078			32,~~876~~950
Depreciation and amortization		4,~~577~~699			3,~~535~~561
EBITDA from continuing operations (a)		46,528			30,149
EBITDA from continuing operations		92,658			77,554
(Increase) / decrease in the fair value of derivative instruments		(13,~~906~~261	)		(34,~~392~~702	)
Loss on redemption of debt		~~1,700~~—			—1,132
Adjusted EBITDA (a)		34,322			26,757
Adjusted EBITDA		79,397			73,984
Add / (subtract)
Income tax expense		(1735,~~011~~468	)		(1029,~~077~~836	)
Interest expense, net		(3,~~688~~078	)		(32,~~876~~950	)
Provision for losses on accounts receivable		25,~~648~~225			23,~~148~~334
Increase in accounts receivables		(~~115~~97,~~161~~962	)		(7658,~~952~~338	)
Increase in inventories		(10,324	)		(9,387	)
Decrease in inventories		38,159			11,823
Decrease in customer credit balances		(2329,~~134~~108	)		(2131,~~790~~308	)
Change in deferred taxes		1422,~~980~~878			926,~~482~~306
Change in other operating assets and liabilities		285,~~658~~975			103,~~708~~924
Net cash used in operating activities	$	(8813,~~710~~982	)	$	(723,~~987~~061	)
Net cash used in investing activities	$	(31,~~182~~262	)	$	(1,~~555~~077	)
Net cash provided by financing activities	$	44,634		$	21,947
Net cash provided by (used in) financing activities	$	13,260		$	(40,960	)

2729

~~(a)~~ EBITDA ~~(Earnings from continuing operations before net interest expense, income taxes, depreciation~~ and ~~amortization) and~~ Adjusted EBITDA ~~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;

•

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

•

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

•

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

•

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

•

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

Six Months Ended March 31, 2011

Compared to the Six Months Ended March 31, 2010

Volume

For the six months ended March 31, 2011, retail volume of home heating oil and propane increased by 37.9 million gallons, or 15.0%, to 291.6 million gallons, as compared to 253.7 million gallons for the six months ended March 31, 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 Oil and Propane
Volume - Six months ended March 31, 2010		253.7
Acquisitions		35.3
Impact of colder temperatures		18.1
Net customer attrition		(13.5	)
Lower Margin COD / BID and Commercial Volume		(1.8	)
Conservation and Other		(0.2	)

Change		37.9
Volume - Six months ended March 31, 2011		291.6

Temperatures in our base business geographic areas of operations for the six months ended March 31, 2011 were 7.6% colder than the six months ended March 31, 2010 and approximately 1.8% colder than normal, as reported by the National Oceanic Atmospheric Administration (“NOAA”). Between April 1, 2010 and March 31, 2011, net customer attrition (excluding acquisitions) was 5.4%, 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 months ended March 31, 2011 increased by 5.6 million gallons, or 28.1%, to 25.3 million gallons, as compared to 19.8 million gallons of other petroleum products sold during the six months ended March 31, 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 44.1% for the six months ended March 31, 2011, as compared to 42.1% for the six months ended March 31, 2010. The percentage of heating oil volume sold to residential price-protected customers decreased to 43.3% for the six months ended March 31, 2011, as compared to 44.3% for the six months ended March 31, 2010. For the six months ended March 31, 2011, sales to commercial/industrial customers decreased to 12.6% of total heating oil volume sales, as compared to 13.6% for the six months ended March 31, 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 six months ended March 31, 2011, product sales increased $278.9 million, or 34.3%, to $1.1 billion, as compared to $812.5 million for the six months ended March 31, 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 months ended March 31, 2011, service and installation sales increased $11.8 million, or 13.5%, to $99.9 million, as compared to $88.1 million for the six months ended March 31, 2010, largely due the additional revenue from acquisitions of $11.1 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 months ended March 31, 2011, cost of product increased $244.6 million, or 42.4%, to $820.8 million, as compared to $576.2 million for the six months ended March 31, 2010, due to increases in volume sales of home heating oil and propane and other petroleum products of 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 months ended March 31, 2011 decreased by $0.0047 per gallon, or 0.5%, to $0.9080 per gallon, from $0.9127 per gallon in the six months ended March 31, 2010. Our fiscal 2010 and fiscal 2011 acquisitions have 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 $0.0043 per gallon, or 0.005%. Product sales and cost of product include home heating oil and propane, and other petroleum products.

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)		Per Gallon		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)		Per Gallon		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).

(Increase) Decrease in the Fair Value of Derivative Instruments

During the six months ended March 31, 2011, the increase in the fair value of derivative instruments resulted in the recording of a $27.2 million net credit due to the expiration of certain hedged positions or their realization to cost of product (a $5.0 million credit) and an increase in the market value for unexpired hedges (a $22.2 million credit).

During the six months ended March 31, 2010, the increase in the fair value of derivative instruments resulted in the recording of a $8.1 million net credit due to the expiration of certain hedged positions or their realization to cost of product (a $7.6 million credit), and an increase in the market value for unexpired hedges (a $0.5 million credit).

Cost of Installations and Service

During the six months ended March 31, 2011, cost of installations and service increased $10.5 million, or 11.9%, to $98.7 million, as compared to $88.2 million for the six months ended March 31, 2010, due primarily to an estimated $9.7 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 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.

Delivery and Branch Expenses

For the six months ended March 31, 2011, delivery and branch expenses increased $23.2 million, or 18.6%, to $147.9 million, compared to $124.7 million for the six months ended March 31, 2010. Acquisitions added $15.7 million in delivery and branch expenses. In the base business, delivery and branch expenses increased by $7.6 million due to higher delivery expenses of $2.9 million associated with the increase in volume and the numerous snow storms experienced in the first six months of fiscal 2011 and an increase in bad debt expense and credit card fee of $2.3 million associated with the 32.3% increase in sales. Insurance claims expense also rose by $2.8 million due in part to the extreme winter weather.

Depreciation and Amortization

For the six months ended March 31, 2011, depreciation and amortization expenses increased by $2.2 million, or 30.7%, to $9.3 million, as compared to $7.1 million for the six months ended March 31, 2010.

Depreciation expense was higher by $0.9 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 $2.3 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 in fiscal 2010.

General and Administrative Expenses

For the six months ended March 31, 2011, general and administrative expenses decreased $0.5 million to $10.2 million, from $10.7 million for the six 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 (Loss)

For the six months ended March 31, 2011, operating income increased $29.9 million to $131.6 million, from $101.7 million for the six months ended March 31, 2010, as an increase in gross product profit of $34.3 million, a favorable change in the fair value of derivative instruments of $19.1 million and an improvement in service and installation profitability of $1.4 million was somewhat offset by operating expense increases (including depreciation and amortization) of $24.9 million.

Interest Expense

For the six months ended March 31, 2011, interest expense increased by $0.4 million, or 4.7% to $8.5 million as compared to $8.1 million for the six months ended March 31, 2010. While average long-term debt increased by $8.9 million, the weighted average long-term borrowing rate declined from 10.25% to 9.3% and the corresponding interest expense decreased by $0.2 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 months ended March 31, 2011, the Partnership borrowed on average $28.6 million under its bank credit facility, or $23.9 million higher than the six months ended March 31, 2010 which drove an increase in interest expense of $0.5 million, despite a decline in the interest rate on these borrowings from 5.7% to 4.3%.

Interest Income

For the six months ended March 31, 2011, interest income increased $0.4 million, or 33.4%, to $1.8 million, as compared to $1.4 million for the six months ended March 31, 2010, due to higher finance charge income from acquisitions.

Amortization of Debt Issuance Costs

For the six months ended March 31, 2011, amortization of debt issuance costs was $1.4 million, slightly higher when compared to $1.3 million for the six months ended March 31, 2010.

Gain (Loss) on Redemption of Debt

In November 2010, we 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 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 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 $101.70 per $100 of principal plus accrued interest. The Partnership recorded a loss of $1.1 million.

Income Tax Expense

For the six months ended March 31, 2011 income tax expense increased $12.6 million, to $52.5 million, from $39.9 million for the six months ended March 31, 2010. The increase in income tax expense was mainly due to the higher pretax income of $29.3 million. The current portion of income tax expense was $14.6 million or 12.0% of pretax income.

Net Income

For the six months ended March 31, 2011, net income increased $16.7 million to $69.2 million, from $52.5 million for the six months ended March 31, 2010, as the increase in operating income of $29.9 million was slightly offset by an increase in income tax expense of $12.6 million.

Adjusted EBITDA

For the six months ended March 31, 2011, Adjusted EBITDA increased by $13.0 million, or 12.9%, to $113.7 million as the impact of colder temperatures of 7.6% and the $16.5 million of Adjusted EBITDA provided by fiscal 2010 and 2011 acquisitions was slightly reduced 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.


	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 ~~the~~our ~~home heating oil and propane~~ 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 ~~three~~six months ended ~~December~~March 31, ~~2010~~2011, cash used in operating activities increased by $1526.7 million to $88102.7 million, compared to $7376.0 million of cash used in operating activities during the ~~three~~six months ended ~~December~~March 31, ~~2009~~2010, as a favorable change in cash generated from operations of $64.89 million, a reduction in inventory levels of $25.4 million, lower cash needs to fund trade payables of $76.51 million, and the favorable timing of certain cash payments (options, interest, insurance and income taxes) totaling $813.29 million was reduced by an increase in cash needs to fund accounts receivable of $3877.20 million. The increase in accounts receivable can be attributed to ~~colder~~an ~~temperatures~~increase ofin ~~5.4%~~volume due to acquisitions, colder temperatures and an increase in wholesale product costs. ~~and~~Days ansales ~~overall~~outstanding ~~increase~~as inof ~~our~~March 31, ~~home~~2011 ~~heating~~were ~~oil~~35.6 days as compared to 32.3 days at March 31, 2010 and ~~propane~~ ~~customer~~29.4 ~~base~~days ofat ~~approximately~~March 31, 112009.0 March 2011 was approximately 30%. ~~Days~~colder than March 2010, which resulted in greater consumption and an increase in days sales outstanding. asAt ~~December~~March 31, ~~2010~~2011, ~~were~~we ~~37.7~~reduced ~~days~~our ~~compared~~petroleum products inventory by 14.1 million gallons to 368.21 million ~~days~~gallons atwhen ~~December~~compared to March 31, ~~2009~~2010. ~~and~~This ~~35.2~~reduction ~~days~~in atinventory ~~December~~levels ~~2008~~was due in part to the impact of colder temperatures on volume sales for the month of March for the respective periods. The ~~increase~~decrease in trade payables is primarily due to the increase in our trade credit to $6571.6 million. Towards the end of fiscal 2010, the Partnership restructured its option program, which impacted the payment terms for these options. The Partnership now pays for these options as they expire rather than at the time the hedge is entered into.

Investing Activities

During the ~~three~~six months ended ~~December~~March 31, ~~2010~~2011, we spent $12.67 million for fixed assets as we invested in computer hardware and ~~software~~ software ($01.51 million), refurbished certain physical plants ($0.38 million) and made additions to our fleet and other equipment ($0.8 million). We also completed ~~one~~two ~~acquisition~~acquisitions for $1.68 million.

28During the six months ended March 31, 2010, our capital expenditures totaled $2.7 million, as we invested in computer hardware and software ($0.8 million), refurbished certain physical plants ($0.1 million) and made additions to our fleet and other equipment ($1.8 million).

During the three months ended December 31, 2009, our capital expenditures totaled $1.6 million, as we invested in computer hardware and software ($0.6 million), refurbished certain physical plants ($0.1 million) and made additions to our fleet and other equipment ($0.9 million).

Financing Activities

During the ~~three~~six months ended ~~December~~March 31, ~~2010~~ 2011, we sold $125.0 million 8.875% Senior Notes due 2017 at a price of 99.35350%. 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 $3.58 million and a call premium of $1.4 million, our cash balance increased by $36.85 million, which can be utilized for general partnership purposes. Also during the first ~~quarter~~half of fiscal 2011, we paid distributions of $410.92 million, borrowed $88.4 million under our revolving credit facility and werepaid $56.8 million of these borrowings during the period. As of March 31, 2011, the Partnership had borrowed $1331.16 million under our revolving credit facility.

~~During~~36 the three months ended December 31, 2009, we repurchased 4.3 million common units for $16.9 million in connection with our unit repurchase plan program and paid distributions to our unit holders of $5.1 million.

During the first six months of fiscal 2010, the Partnership repurchased 5.2 million common units for $20.8 million in connection with the unit repurchase plan program and paid distributions to the unit holders of $10.2 million. During the six months ended March 31, 2010, we borrowed $36.8 million under our revolving credit facility and repaid $17.7 million during the period. As of March 31, 2010, the Partnership had $19.1 million borrowed under its revolving credit facility. This amount was subsequently repaid by May 2010.

On February 19, 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 ~~December~~March 31, ~~2010~~2011, or a combination thereof. To the extent future capital requirements ~~exceed~~ exceed cash on hand plus cash flows from operating activities, we anticipate that working capital will be financed by our revolving credit facility.

Our asset based revolving credit facility provides us with the ability to borrow up to $240 million ($290 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 $50 million without the consent of the bank group. However, the bank group is not obligated to fund the $50 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 secured by liens on substantially all of our assets, including accounts receivable, inventory, general intangibles, real property, fixtures and equipment. As of ~~December~~March 31, ~~2010~~2011, $4231.6 million was outstanding for working capital borrowings and $46.7 million in letters of credit were outstanding, of which $4246.4 million are for current and future insurance reserves and bonds and $0.3 million are for seasonal inventory purchases and other working capital purposes. ~~Working~~Our ~~capital~~revolving ~~borrowing~~credit ~~outstanding~~facility asexpires ~~of December~~on July 312, ~~2010~~2012 ~~were~~and ~~$13.1~~we ~~million~~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 $43.5 million (15% 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 ~~December~~March 31, ~~2010~~ 2011, availability, as defined in the amended and restated credit agreement, was $~~155~~181.15 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.

The 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 $51.05 to $72.05 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 ~~will~~may make cash contributions to fund its frozen defined benefit pension obligations of approximately $2.61 million for the balance of fiscal 2011. WeShould ~~anticipate~~the ~~paying~~Partnership maintain its current distribution rate, we would pay distributions of approximately $1510.75 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

2937

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 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 ~~January~~April 2514, 2011, we declared a quarterly distribution of $0.0775 on all of our common units, payable on ~~February~~May 1413, 2011 to holders of record on ~~February~~May 45, 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.

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 ~~December~~March 31, ~~2010~~2011, we had outstanding borrowings totaling $~~138~~155.18 million (excluding discounts), of which approximately $1331.16 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 $0.13 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 ~~December~~March 31, ~~2010~~2011, the potential impact on our hedging activity would be to increase the fair market value of these outstanding derivatives by $1311.79 million to a fair market value of $3138.50 million; and conversely a hypothetical ten percent decrease in the cost of product would decrease the fair market value of these outstanding derivatives by $(910.05) million to a fair market value of $815.86 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 ~~December~~March 31, ~~2010~~2011. Based on that evaluation, such principal executive officer and principal financial officer concluded that the Partnership’s disclosure controls ~~and~~ and procedures were effective as of ~~December~~March 31, ~~2010~~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~~ 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~~ 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~~ 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.

On May 10, 2010, the ~~Company~~Partnership completed the acquisition of Champion Energy Corporation (“CEC”). The ~~Company~~Partnership is in process of integrating CEC. The ~~Company~~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 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.

30(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 company have been detected.

~~internal~~Therefore, a control ~~over~~system, ~~financial~~no ~~reporting~~matter ~~during~~how ~~the~~well ~~Partnership’s~~conceived ~~most~~and ~~recent~~operated, ~~fiscal~~can ~~quarter~~provide only reasonable, not absolute, assurance that ~~has~~the ~~materially~~objectives ~~affected,~~of orthe iscontrol ~~reasonably~~system ~~likely~~are met. Our disclosure controls and procedures are designed to ~~materially~~provide ~~affect~~such ~~the Partnership’s~~reasonable ~~internal~~assurances of achieving our desired control ~~over~~objectives, and the principal executive officer and principal financial ~~reporting~~officer of our general partner have concluded, as of March 31, 2011, that our disclosure controls and procedures were effective in achieving that level of reasonable assurance.

(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 company 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 December 31, 2010, 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 ~~three~~six months ended ~~December~~March 31, ~~2010~~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.

3139

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	~~February~~May 74, 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	~~February~~May 74, 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	~~February~~May 74, 2011
Richard F. Ambury	Financial Officer, Treasurer and Secretary
	(Principal Financial Officer)
Signature	Title	Date
/S/ RICHARD G. OAKLEY	Vice President - Controller	~~February~~May 74, 2011
Richard G. Oakley	(Principal Accounting Officer)

3240

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DuringTable the first quarter of fiscal 2011, the Partnership repurchased $82.5 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 $1.7 million for this transaction. Contents

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