UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended September 30, ~~2006~~ 2009

¨	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

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 ofincorporation or organization)		(I.R.S. Employer Identification No.)
(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)		(Zip Code)

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

(203) 328-7310

(Registrants’ telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:


Title of each class		Name of each exchange on which registered
Common Units		New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No x.

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No x

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

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 (§232.405 of this chapter) 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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer, or a smaller reporting company. See ~~definition~~definitions of “large accelerated filer,” and ~~large~~ “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Act (check one).

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

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

The aggregate market value of Star Gas Partners, L.P. Common Units held by non-affiliates of Star Gas Partners, L.P. on March 31, ~~2006 was~~2009 was approximately $89197,~~627~~013,000. As of ~~December~~November 1430, ~~2006~~2009, the registrants had units and shares outstanding for each of the issuers’ classes of common stock as follows:

Star Gas Partners, L.P.	Common Units	7571,~~774~~714,~~336~~982
Star Gas Partners, L.P.	General Partner Units	325,729
Star Gas Finance Company	Common Shares	100

Documents Incorporated by Reference: None

STAR GAS PARTNERS, L.P.

~~2006~~2009 FORM 10-K ANNUAL REPORT

TABLE OF CONTENTS

		Page
	PART I
Item 1.	Business	3
Item 1A.	Risk Factors	8
Item 1B.	Unresolved Staff Comments	1416
Item 2.	Properties	1416
Item 3.	Legal Proceedings—Litigation	1416
Item 4.	Submission of Matters to a Vote of Security Holders	1416
	PART II
Item 5.	Market for the Registrant’s Units and Related Matters	1517
Item 6.	Selected Historical Financial and Operating Data	1619
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	1822
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	3546
Item 8.	Financial Statements and Supplementary Data	3546
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	3546
Item 9A.	Controls and Procedures	3546
Item 9B.	Other Information	3647
	PART III
Item 10.	Directors and Executive Officers of the Registrant	3648
Item 11.	Executive Compensation	4051
Item 12.	Security Ownership of Certain Beneficial Owners and Management	4262
Item 13.	Certain Relationships and Related Transactions	4362
Item 14.	Principal Accounting Fees and Services	4364
	PART IV
Item 15.	Exhibits and Financial Statement Schedules	4464

PART I

ITEM 1. BUSINESS

Statement Regarding Forward-Looking Disclosure

This Annual Report on Form 10-K 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, the consumption patterns of our customers, our ability to obtain satisfactory gross profit margins, our ability to obtain new accounts and retain existing accounts, our ability to ~~effect~~make strategic acquisitions ~~or redeploy assets~~, the impact of litigation, ~~the continuing impact of the business process redesign project and~~ our ability to ~~address issues related to that project, our ability to~~ contract for our current and future supply needs, natural gas conversions, future union relations and the outcome of ~~current and future~~ union negotiations, the impact of current and future environmental, health, and safety regulations, the ability to attract and retain employees, customer credit worthiness, ~~and~~counterparty credit worthiness, marketing plans., and general economic conditions. 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. 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 ~~have~~be ~~been~~ 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 Initiatives and Strategy.” Without limiting the foregoing, the words “believe”,” “anticipate”,” “plan”, ” “expect”,” “seek”,” “estimate,” and similar expressions are intended to identify forward-looking statements. Important factors that could cause actual results to differ materially from our expectations (“Cautionary Statements”) are disclosed in this Annual Report on Form 10-K. 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.

ITEM 1.

BUSINESS

Structure

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 ~~September~~November 30, ~~2006~~2009, had outstanding 7571.87 million common units (NYSE: “SGU”) representing ana 99.65% limited partner interest in Star Gas Partners), and 0.3 million general partner units, (representing ana 0.45% 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 ~~heating oil~~ operations are conducted through Petro Holdings, Inc. (~~“Petro”) and its subsidiaries. Petro is~~ a Minnesota corporation that is aan indirect wholly- owned subsidiary of ~~Star/Petro,~~the ~~Inc.~~Partnership ) and its subsidiaries (“~~Star/~~Petro”),. ~~which~~Petro is a ~~wholly~~Northeast and Mid-~~owned~~Atlantic ~~subsidiary~~region retail distributor of ~~the~~home ~~Partnership~~heating oil and related services.

• Star Gas Finance Company is a ~~wholly~~100% owned subsidiary of the Partnership. Star Gas Finance Company serves as the co-issuer, jointly and severally with the Partnership, of the Partnership’s $~~172~~133.81 million 10 ~~1/4~~.25% Senior Notes, which are due in 2013. The Partnership is dependent on distributions including ~~intercompany~~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.

We file annual, quarterly, current and other reports and information with the SEC. These filings can be viewed and downloaded from the Internet at the SEC’s website at www.sec.gov. In addition, these SEC filings are available at no cost as soon as reasonably practicable after the filing thereof on our website at www.star-gas.com/~~Edgar~~sec.cfm. These reports are also available to be read and copied at the SEC’s public reference room located at Judiciary Plaza, 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the public reference room by calling the SEC at 1-800-SEC-0330. You may also obtain copies of these filings and other information at the offices of the New York Stock Exchange located at 11 Wall Street, New York, New York 10005.

Recapitalization

Effective as of April 28, 2006, the Partnership completed its recapitalization pursuant to the terms of a unit purchase agreement dated as of December 5, 2005, as amended, by and among, the Partnership, Star Gas LLC (the former general partner), Kestrel and its wholly-owned subsidiaries, Kestrel Heat (the new general partner) and KM2, LLC, a Delaware limited liability company (“M2”). (See Note 3 – Recapitalization to the Consolidated Financial Statements)

Business Overview

As of September 30, ~~2006~~2009, we ~~serviced~~sold home heating oil to approximately ~~430~~374,000 full service residential and commercial home heating oil customers ~~from~~and ~~locations~~propane into ~~the~~approximately ~~Northeast~~7,000 ~~and~~propane ~~Mid-Atlantic regions~~customers. We believe we are the largest retail distributor of home heating oil in the United States. In ~~addition~~We toalso ~~selling~~sell home heating oil, wegasoline and diesel fuel to approximately 34,000 customers on a delivery only basis. We install, maintain, and repair heating and air conditioning equipment. Tofor aour ~~limited~~customers ~~extent,~~and weprovide ~~also~~ancillary ~~market~~home ~~other~~services, ~~petroleum products~~ including ~~diesel~~home ~~fuel~~security and ~~gasoline~~plumbing, to approximately 1011,000 ~~commercial~~ customers. During fiscal ~~2006~~2009, total sales were comprised of approximately 7579% from sales of home heating oil; 15% from the installation and repair of heating and air conditioning equipment and ancillary services; and 106% from the sale of other petroleum products. We provide home heating equipment repair service 24 hours a day, seven days a week, 52 weeks a year. These services are an integral part of our heating oil business, and are intended to maximize customer satisfaction and loyalty.

In fiscal ~~2006~~2009, sales to residential customers represented 8588% of the retail heating oil gallons sold and 9295% of heating oil gross profits.

We have operations and markets in the following states, regions and counties:

Connecticut Massachusetts New York Rhode Island Fairfield Suffolk Dutchess Providence New Haven Norfolk Ulster Kent Middlesex Essex Orange Washington Litchfield Bristol Westchester Newport Hartford Middlesex Putnam Bristol Barnstable Nassau Maryland Plymouth Suffolk Virginia Baltimore Worcester ~~Queens~~Bronx Loudoun Harford ~~Kings~~Queens Prince William Cecil New Jersey ~~Richmond~~Kings Fauquier Anne Arundel Salem ~~New~~Richmond ~~York~~ Stafford Carroll Gloucester New York Arlington Howard Camden ~~Pennsylvania~~ Fairfax Montgomery Burlington ~~Philadelphia~~Pennsylvania Prince George’s Ocean ~~Bucks~~Philadelphia Washington, D.C. Calvert Monmouth ~~Montgomery~~Bucks District of Columbia Charles Somerset ~~Chester~~Montgomery Frederick Middlesex ~~Lehigh~~Chester Mercer ~~Northampton~~Lancaster Hunterdon ~~Berks~~Lebanon Union ~~Monroe~~Lehigh Hudson ~~Dauphin~~Northampton Bergen ~~Cumberland~~Berks Essex ~~York~~Monroe Passaic Dauphin Sussex Cumberland Morris York Warren

Industry Characteristics

Home heating oil is primarily used as a source of fuel to heat residences and businesses in the Northeast and Mid-Atlantic regions. According to the U.S. Department of Energy—Energy Information Administration, 2005 Residential Energy Consumption Survey (the latest survey published), these regions account for 81% of the households in the United States where heating oil is the main space-heating fuel and 31% of the homes in these regions use home heating oil as their main space-heating fuel. In recent years, as the price of home heating oil increased, customers have tended to increase their conservation efforts, which has decreased their consumption of home heating oil.

The retail home heating oil industry is mature, with total market demand expected to decline in the foreseeable future due to conversions to natural gas. Our customer losses to natural gas have recently increased. In each of the fiscal years 2009 and 2008, we lost 1.6% of our home heating oil customer base to natural gas conversions, which compares to an approximate 1.0% per annum loss in prior years. Therefore, our ability to maintain our business or grow within the industry is dependent on the acquisition of other retail distributors as well as the success of our marketing programs. It is common practice in our

~~Industry~~ business ~~Characteristics~~to price products to customers based on a per gallon margin over wholesale costs. As a result, we believe distributors such as ourselves generally seek to maintain their per gallon margins by passing wholesale price increases through to customers, thus insulating themselves from the volatility in wholesale heating oil prices. However, distributors may be unable or unwilling to pass the entire product cost increases through to customers. In these cases, significant decreases in per gallon margins may result. The timing of cost pass-throughs can also significantly affect margins. The retail home heating oil industry is highly fragmented, characterized by a large number of relatively small, independently owned and operated local distributors. Some dealers provide full service, as we do, and others offer delivery only on a cash-on-delivery basis, which we also do to a significantly lesser extent. The industry is becoming more complex and costly due to increasing regulations, working capital requirements, including the cost to hedge for protected price customers. We utilize derivative instruments in order to hedge a substantial majority of the heating oil volume we expect to sell to protected price customers that have renewed their protected price plans, mitigating our exposure to changing commodity prices. We also use derivative instruments as a hedge against our physical inventory and priced purchase commitments. We do not enter into any forward hedges for our variable price customers.

Home heating oil is primarily used as a source of fuel to heat residences and businesses in the New England and Mid-Atlantic regions. According to the U.S. Department of Energy—Energy Information Administration, 2001 Residential Energy Consumption Survey (the latest survey published), these regions account for 77% of the households in the United States where heating oil is the main space-heating fuel and 31% of the homes in these regions use home heating oil as their main space-heating fuel. In recent years, as the price of home heating oil increased, customers have tended to increase their conservation efforts, which has decreased their consumption of home heating oil. Weather conditions have a significant impact on demand for home heating oil as we have seen in fiscal 2006 and fiscal 2002 when temperatures were significantly warmer than normal for the areas in which we sell home heating oil.

The retail home heating oil industry is mature, with total market demand expected to decline in the foreseeable future due to conversions to natural gas. We have lost an average of 1.0% of our customers per year over the last five years due to conversions to natural gas. Therefore, our ability to grow within the industry is dependent on the acquisition of other retail distributors as well as the success of our marketing programs designed to attract and retain customers to help offset customer losses. It is common practice in the home heating oil distribution industry to price products to customers based on a per gallon margin over wholesale costs. As a result, we believe distributors such as ourselves generally seek to maintain their margins by passing wholesale price increases through to customers, thus insulating themselves from the volatility in wholesale heating oil prices. However, during periods of significant volatility in wholesale prices, which occurred over the last three fiscal years, distributors may be unable or unwilling to pass the entire product cost increases through to customers. In these cases, significant decreases in per gallon margins may result. The timing of cost pass-throughs can also significantly affect margins. The retail home heating oil industry is highly fragmented, characterized by a large number of relatively small, independently owned and operated local distributors. Some dealers provide full service, like ourselves, and others offer delivery only on a cash on delivery basis. The industry is becoming more complex and costly due to increasing regulations, working capital requirements and the need to hedge. We purchase derivative instruments (futures, options and swaps) in order to hedge a substantial majority of the heating oil volume we expect to sell to protected-price customers that have renewed their price plans, mitigating our exposure to changing commodity prices.

Business Initiatives and Strategy

~~Prior~~We toare ~~the~~committed ~~fiscal~~to ~~2004~~our ~~winter~~strategy ~~heating season, we attempted~~ to ~~develop~~increase aunitholder ~~competitive~~value ~~advantage~~and inincrease ~~customer~~distributions ~~service~~over time through ~~a business process redesign~~(i) reduced ~~project~~net ~~and,~~customer ~~as part of that effort~~attrition, ~~centralized~~(ii) operational ~~our~~efficiencies ~~heating equipment service~~ and ~~oil~~productivity ~~dispatch~~improvements, ~~functions~~ and ~~engaged~~(iii) increased amarket ~~centralized~~share ~~customer~~through ~~care~~the ~~center~~acquisition ~~to fulfill our telephone requirements for a majority~~ of ~~our~~other ~~home~~ heating oil ~~customers.~~distributors ~~We experienced~~or ~~difficulties in advancing this initiative, which adversely impacted~~ the ~~customer~~possible ~~base~~expansion ininto ~~fiscal~~other ~~years~~energy ~~2004,~~or petroleum-related ~~2005 and 2006~~businesses.

~~We believe~~To weengage ~~have~~our ~~identified~~employees ~~the~~and ~~problems~~enhance ~~associated~~their ~~with~~abilities ~~the~~to ~~past~~provide ~~centralization~~superior ~~efforts~~customer service and reduce ~~continue~~gross tocustomer ~~address~~losses, ~~these~~we ~~issues.~~require ~~Our~~all ~~goal~~employees is to ~~reestablish~~attend a ~~more~~team-building ~~traditional~~and ~~customer~~role-playing ~~service~~program ~~model~~that inwe ~~which~~call ~~the~~Boot ~~majority~~Camp. ofThe ~~the~~initiatives ~~customer~~covered ~~service~~in ~~calls will~~Boot beCamp ~~handled~~are ~~locally~~consistently inreinforced ~~each~~through ~~district~~constant ~~with~~customer ~~minimal~~service ~~reliance~~monitoring onand training ain ~~centralized~~the ~~call center~~field. WeIn ~~initiated~~addition, ~~this~~we ~~change~~have ~~with~~recently acreated ~~test~~an ininternal, ~~several~~Director-level ~~districts~~position, tocalled ~~measure~~ the ~~impact~~Director ~~on retention~~ of ~~customers~~Quality asAssurance. ~~well~~This asposition tois ~~get~~responsible afor ~~better~~the ~~understanding~~customer ofservice ~~what our~~evaluation ~~local~~process ~~needs~~and ~~would~~directs ~~be.~~the ~~Based~~teams onthat ~~the~~conduct district ~~results~~quality ofassurance ~~these~~assessments. ~~tests,~~These weassessments ~~have~~are ~~begun~~focused toon ~~move~~escalating ~~forward~~the ~~more~~performance ~~aggressively~~in ~~with~~customer ~~our~~relations ~~return~~and toretention aand ~~more~~on ~~localized~~driving customer service ~~model~~performance to the best possible level.

~~Going~~Seasonality forward, our strategy is to increase unit-holder value through (i) reduced net customer attrition, (ii) operational efficiencies and productivity improvements, and (iii) increased market share through the acquisition of other heating oil distributors or the possible expansion into other energy or petroleum-related businesses.

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 results in the sale of approximately 30% of our volume of home heating oil in the first fiscal quarter and 45% of our volume in the second fiscal quarter of each fiscal year, the peak heating season. In addition, sales volume typically fluctuates from year to year in response to variations in weather, wholesale energy prices and other factors.

Competition

Most of our district locations compete with numerous distributors, primarily on the basis of reliability of service, price, and response to customer needs. Each district location operates in its own competitive environment.

We compete with distributors offering a broad range of services and prices, from full-service distributors, like ourselves, to those offering delivery only. Like many companies in the home heating oil business, we provide home heating equipment repair service on a 24-hour-a-day, seven-day-a-week, 52 weeks a year basis. We believe that this level of service tends to help build customer loyalty. In some instances homeowners have formed buying cooperatives that seek to purchase fuel oil from distributors at a price lower than individual customers are otherwise able to obtain. We also compete for retail customers with suppliers of alternative energy products, principally natural gas, propane and electricity. The expansion of natural gas into traditional home heating oil markets in the Northeast has historically been inhibited by the capital costs required to expand distribution and pipeline systems.

Customers and Pricing

Our full service home heating oil customer base is comprised of 97% residential customers ~~(95%)~~ and 3% commercial customers ~~(5%)~~. Our residential customer receives small deliveries on average of ~~170~~160 gallons ~~per delivery~~ and our commercial accounts receive larger deliveries on average of ~~425~~350 gallons. Typically, we make four to six deliveries per customer per year. ~~Deliveries are scheduled based on each customer’s historical consumption pattern and prevailing weather conditions.~~ Currently, 9690% of our deliveries are scheduled automatically and 4 10% of our home heating oil customer base call from time to time to schedule a delivery. Automatic deliveries are scheduled based on each customer’s historical consumption pattern and prevailing weather conditions. Our practice is to bill customers promptly after delivery. We also offer a ~~budget~~balanced payment plan in which a customer’s estimated annual oil purchases and service contract fees are paid for in a series of equal monthly payments. ~~and~~Approximately 3034% of our residential home heating oil customers have ~~elected~~selected this billing option.

We offer several pricing alternatives to our customers. Our variable pricing program allows the price to float with the home heating oil market and generally move up or down in response to market changes and other factors. In addition, we offer price protection programs, which establish either a ~~fixed~~ceiling or a ~~maximum~~fixed per gallon price that the customer would pay over ~~the~~a ~~following~~defined ~~12-month~~ period. ~~At September 30,~~Over ~~2006,~~the ~~41 %~~last ofseveral ~~our~~years, ~~total~~a ~~home~~greater ~~heating~~number ~~oil~~of ~~customer~~our ~~base~~price ~~had~~protected acustomers ~~price~~have ~~protection~~selected ~~plan~~the asceiling ~~compared~~plan toover ~~38 %~~the atfixed ~~September 30.~~price ~~2005~~plan.

Sales to residential customers ordinarily generate higher margins than sales to commercial customers. Due to the greater price sensitivity of residential protected price customers, the per gallon margins realized from these customers generally are less than variable priced residential customers. Per gallon gross profit margins can also vary by geographic region. Accordingly, per gallon gross profit margins could vary significantly from year to year in a period of identical sales volumes.


	As of September 30th
	2009		2008
Variable	52.3	%	48.6	%
Ceiling	44.6	%	34.4	%
Fixed	3.1	%	17.0	%

	100.0	%	100.0	%

Sales to residential customers ordinarily generate higher per gallon margins than sales to commercial customers. Due to greater price sensitivity and hedging complexities of residential protected price customers, the per gallon margins realized from price protected customers generally are less than variable priced residential customers.

Customer Attrition

We measure net customer attrition for our full service residential and commercial home heating oil customers. Net customer attrition is the difference between gross customer losses and customers added through internal marketing efforts. Customers added through acquisitions are not included in the calculation of ~~net~~gross customer ~~attrition~~gains. Gross customer losses are the result of a number of factors, including price competition, move outs, service issues, ~~and~~ credit losses and conversions 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.

For fiscal ~~2006~~2009, we lost 2930,~~600~~200 accounts (net), or 67.65% of our home heating oil customer base, as compared to fiscal ~~2005~~2008, where ~~in which~~ we lost 3518,~~100~~300 accounts (net), or 74.14% of our home heating oil customer base. In fiscal ~~2004,~~2007 we lost 3321,~~100~~300 accounts (net), or 65.40% of our home heating oil customer base. Our net customer attrition increased in fiscal 2009 when compared to fiscal 2008, as gross losses (which is reflective of customer turn-over) increased to 21.0% in fiscal 2009, as compared to 19.1% in fiscal 2008 and 17.6% in fiscal 2007. (See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Customer Attrition)

Suppliers and Supply Arrangements

We purchase home heating oil for delivery in either barge, pipeline or truckload quantities, and have contracts with approximately ~~100~~60 third-party terminals for the right to temporarily store heating oil at ~~facilities~~their ~~we do not own~~facilities. Purchases are made under supply contracts or on the spot market. WeIncluding ~~enter~~our own physical storage, we have entered into market price based contracts for approximately a77% ~~majority~~ of our home heating oil requirements for fiscal 2010. During fiscal ~~2006~~2009, Sunoco Inc., Global Companies, and NIC Holding Corp., ~~and~~(Northville ~~Global~~Industries) ~~Companies~~ provided 2115.41%, 1613.85% and 128.37% respectively, of our product purchases. Aside from these three suppliers, no single supplier provided more than 10% of our product supply during fiscal ~~2006~~2009. ~~Supply~~For fiscal 2010, we have supply contracts for similar quantities with Sunoco Inc., Global Companies, and NIC Holding Corp. Supply contracts typically have terms of 6 to 12 months. All of the supply contracts provide for minimum quantities. In all cases, the supply contracts do not establish in advance the price of fuel oil. This price is based upon a published market index price at the time of delivery or pricing date plus an agreed upon differential. We believe that our policy of contracting for the majority of our anticipated supply needs with diverse and reliable sources will enable us to obtain sufficient ~~product~~ product should unforeseen shortages develop in worldwide supplies.

Derivatives

We use derivative instruments in order to mitigate our exposure to market risk associated with the purchase of home heating oil for our protected price customers, physical inventory on hand, inventory in transit and priced purchase commitments. At September 30, 2006 we had outstanding derivative instruments with the following banks or brokers: Wachovia Bank, NA, Fimat, BP North America Petroleum, Cargill, LaSalle Bank, NA, Morgan Stanley, JPMorgan Chase Bank, NA, Societe Generale, Citibank, N.A., and Bank of America, N.A.

~~SFAS~~The ~~No.~~Financial ~~133,~~Accounting Standards Board (“FASB”) Accounting ~~for~~Standards ~~Derivative~~Codification ~~Instruments~~(“ASC”) 815-10-05 Derivatives and Hedging ~~Activities~~topic (“SFAS No. 133”), 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. ToCurrently, the ~~extent~~Partnership ~~derivative~~has ~~instruments~~elected ~~designated~~not asto ~~cash~~designate ~~flow~~its ~~hedges~~derivative ~~are~~instruments ~~effective~~as ~~and~~hedging ~~SFAS~~instruments ~~133~~under ~~documentation~~this ~~requirements~~standard, ~~are~~and ~~met,~~the ~~changes~~change in fair value ~~are~~of ~~recognized in other comprehensive income until~~ the ~~forecasted~~ ~~hedged~~derivative ~~item~~instruments isare recognized in ~~earnings. Currently, none of~~ our ~~derivative~~statement ~~instruments qualify for hedge accounting treatment because we have not met the documentation requirements~~ of ~~SFAS 133~~operations. ~~Therefore, we could experience great volatility in earnings as these currently outstanding derivative instruments are marked to market.~~ While we largely expect our realized ~~derivative gains and losses to be offset by increases or decreases in the value of our physical purchases, we~~ will experience volatility in reported earnings due to the recording of unrealized gains and losses on our derivative instruments that do not qualify for hedge accounting for the periods in which we hold such derivative instruments prior to their maturity. The Partnership is currently evaluating whether to elect hedge accounting for future periods.

Home Heating Oil Price Volatility

The wholesale price of home heating oil has been extremely volatile over the last three fiscal years and has resulted in increased consumer price sensitivity to heating costs and increased net customer attrition. Like any other market commodity, the price of home heating oil is generally set by various economic and geopolitical forces. Rapid global economic expansion is fueling an ever-increasing demand for oil. 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. Crude oil is bought and sold in the international marketplace and as such is significantly affected by the economic forces of worldwide supply and demand. The volatility in home heating oil wholesale cost, as measured by the New York Mercantile Exchange (“Nymex”) for fiscal 2006, 2005 and 2004 by quarter, is illustrated by the following chart:

	Fiscal 2006				Fiscal 2005				Fiscal 2004
	Low		High		Low		High		Low		High
Quarter Ended
December 31	$	1.6097	$	2.0809	$	1.2108	$	1.5944	$	0.7728	$	0.9642
March 31		1.6075		1.8843		1.1922		1.6576		0.8645		1.0384
June 30		1.8558		2.0964		1.3508		1.6761		0.8472		1.0641
September 30		1.6472		2.1435		1.5609		2.1985		1.0606		1.3917

In derivative agains ~~volatile~~and ~~market~~losses ~~even~~to ~~small~~be ~~changes~~offset inby ~~supply~~increases or ~~demand~~decreases ~~can~~in ~~dramatically~~the ~~affect~~value ~~prices.~~of ~~Heating~~our ~~oil~~physical ~~prices~~purchases, ~~are subject~~we towill ~~price~~experience ~~fluctuations~~volatility ifin ~~demand~~reported ~~rises~~earnings ~~sharply~~due ~~because~~to ofthe ~~excessively~~recording ~~cold~~of ~~weather~~unrealized non-cash gains and~~/or~~ ~~disruptions~~losses aton ~~refineries~~our ~~and~~derivative ~~instability~~instruments inprior ~~key~~to ~~oil~~their ~~producing regions~~maturity.

~~Competition~~Home Heating Oil Price Volatility

WeIn ~~compete~~recent ~~with~~years, ~~distributors~~the ~~offering~~wholesale aprice ~~broad range~~ of ~~services and prices, from full-service distributors, like ourselves, to those offering delivery only. Like many companies in the~~ home heating oil ~~business,~~has webeen ~~provide~~extremely ~~home heating equipment repair service on a 24-hour-a-day~~volatile, ~~seven-day-a-week,~~resulting 52in ~~weeks~~increased aconsumer ~~year basis. This tends to build customer loyalty. In some instances homeowners have formed buying cooperatives that seek to purchase fuel oil from distributors at a~~ price ~~lower~~sensitivity ~~than individual customers are otherwise able~~ to ~~obtain. We also compete for retail~~ ~~customers~~heating ~~with~~costs ~~suppliers~~and ofincreased ~~alternative~~gross ~~energy~~customer ~~products, principally natural gas, propane, and electricity~~attrition. ~~The~~Like ~~rate~~any ofother ~~conversion~~market ~~from~~commodity, the ~~use~~price of home heating oil ~~to natural gas~~ is ~~primarily~~generally ~~affected~~impacted by ~~the~~many ~~relative~~factors, ~~retail~~including ~~prices~~economic ofand ~~the~~geopolitical ~~two products~~forces. ~~and~~The ~~the~~price ~~cost~~ of ~~replacing~~home anheating oil ~~fired~~is ~~heating~~closely ~~system~~linked to ~~with~~the ~~one~~price ~~that~~refiners ~~uses~~pay ~~natural~~for ~~gas~~crude oil, inwhich ~~addition~~is tothe ~~environmental~~principal ~~concerns.~~cost Wecomponent ~~believe that approximately 1%~~ of ~~the~~ home heating oil ~~customer base annually converts from home heating oil to natural gas~~. The ~~expansion~~volatility ofin ~~natural~~the ~~gas~~wholesale ~~into~~cost ~~traditional~~of home heating oil, ~~markets~~as inmeasured by the ~~Northeast~~New ~~has~~York ~~historically~~Mercantile ~~been~~Exchange ~~inhibited~~(“Nymex”) byfor ~~the~~fiscal ~~capital~~2009, ~~costs~~2008 and ~~required~~2007 toby ~~expand~~quarter, ~~distribution~~is ~~and~~illustrated ~~pipeline~~by ~~systems.~~the following chart:

Most of our branch locations compete with several distributors, primarily on the basis of reliability of service, price, and response to customer needs. Each branch location operates in its own competitive environment.


	Fiscal 2009				Fiscal 2008				Fiscal 2007
	Low		High		Low		High		Low		High
Quarter Ended
December 31	$	1.1983	$	2.8469	$	2.1596	$	2.7066	$	1.5869	$	1.8477
March 31		1.1331		1.6263		2.4188		3.1483		1.4707		1.8794
June 30		1.3147		1.8630		2.8797		3.9748		1.7978		2.0424
September 30		1.5038		1.9569		2.7197		4.1060		1.9393		2.2609

Seasonality

Our fiscal year ends on September 30. All references to quarters and years in this document are to fiscal quarters and years unless otherwise noted. The seasonal nature of our business results in the sale of approximately 30% of our volume in the first quarter and 45% of our volume in the second quarter of each fiscal year, the peak heating season. We generally realize net income the first and second fiscal quarters and net losses during the third and fourth fiscal quarter.

Acquisitions

WeIn ~~made~~fiscal no2009, ~~acquisitions~~we incompleted ~~fiscal~~the ~~2006~~purchase ~~and~~of ~~2005~~one retail heating oil dealer with approximately 3,800 home heating oil customers for an aggregate cost of approximately $4.0 million, reduced by $0.7 million of working capital credits. In fiscal ~~2004~~2008, we completed the purchase of ~~three~~seven retail heating oil dealers with approximately 5,700 home heating oil customers and one small home security business for an aggregate cost of approximately $32.5 6 million., reduced ~~Under~~by ~~the~~$0.7 ~~terms~~million of ~~our~~working ~~revolving~~capital ~~credit~~credits. ~~facility,~~In ~~there~~fiscal ~~are~~2007, ~~limitations~~we oncompleted the ~~size~~purchase of ~~individual~~seven ~~acquisitions~~retail ~~and~~heating anoil ~~annual~~dealers ~~limitation~~with onapproximately ~~total~~19,400 ~~acquisitions.~~home ~~There~~heating ~~are~~oil ~~also~~customers ~~certain~~and ~~financial~~several ~~tests~~thousand ~~that~~plumbing ~~must~~customers befor ~~satisfied before~~ an ~~acquisition~~ ~~can~~aggregate becost ~~consummated~~of $26.4 million.

Employees

As of September 30, ~~2006~~2009, we had 2,~~610~~655 employees, of whom ~~736~~825 were office, clerical and customer service personnel; ~~935~~844 were ~~heating~~ equipment ~~repairmen~~technicians; ~~365~~360 were oil truck drivers and mechanics; ~~385~~356 were management and ~~189~~270 were employed in sales. Of these employees ~~1,100~~951 are represented by 2021 different local chapters of labor unions. Some of these unions have union administered pension plans that have significant unfunded liabilities, a portion of which could be assessed to us should we withdraw from these plans. The Partnership does not expect to withdraw from these plans. In addition, approximately ~~400~~378 seasonal employees (275 of which are represented by the local chapters of labor unions indicated earlier) are rehired annually to support the requirements of the heating season. We are currently involved in ~~one~~4 union ~~negotiation~~negotiations. We believe that our relations with both our union and non-union employees are generally satisfactory.

Government Regulations

We are subject to various federal, state and local environmental, health and safety laws and regulations. Generally, these laws impose limitations on the discharge of pollutants and establish standards for the handling of solid and hazardous wastes. These laws include the Resource Conservation and Recovery Act, the Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), the Clean Air Act, the Occupational Safety and Health Act, the Emergency Planning and Community Right to Know Act, the Clean Water Act and comparable state statutes. CERCLA, also known as the “Superfund” law, imposes joint and several liabilities without regard to fault or the legality of the original conduct on certain classes of persons that are considered to have contributed to the release or threatened release of a hazardous substance into the environment. ~~Heating~~ ~~oils~~Products stored and/or delivered by the Partnership and certain automotive waste products generated by the Partnership’s fleet are hazardous substances within the meaning of CERCLA. These laws and regulations could result in civil or criminal penalties in cases of non-compliance or impose liability for remediation costs. The Partnership is currently a named “potentially responsible party” in one CERCLA civil enforcement action. This action is in its early stages of litigation with preliminary discovery activities taking place. We do not believe that this action will have a material impact on our financial condition or results of operations.

In addition, transportation of distillates and gasoline by truck are subject to regulations promulgated under the Federal Motor Carrier Safety Act. These regulations cover the transportation of hazardous materials and are administered by the United States Department of Transportation or similar state agencies. We conduct ongoing training programs to help ensure that our operations are in compliance with applicable safety regulations. We maintain various permits that are necessary to operate some of our facilities, some of which may be material to our operations.

With respect to the transportation of distillates and gasoline by truck, we are subject to regulations promulgated under the Federal Motor Carrier Safety Act. These regulations cover the transportation of hazardous materials and are administered by the United States Department of Transportation or similar state agencies. We conduct ongoing training programs to help ensure that our operations are in compliance with applicable safety regulations. We maintain various permits that are necessary to operate some of our facilities, some of which may be material to our operations.

Trademarks and Service Marks

We market our products and services under various trademarks, which we own. They include marks such as Petro and Meenan. We believe that the Petro, Meenan and other trademarks and service marks are an important part of our ability to attract new customers and to effectively maintain and service our customer base.

ITEM 1A.

RISK FACTORS

An investment in the Partnership involves a high degree of risk. Security holders and ~~Investors~~investors should carefully review the following risk factors.

~~Unitholders~~Current ~~May~~economic ~~Have~~conditions ~~to Report~~could ~~Income~~adversely ~~for~~affect ~~Federal~~our ~~Income~~results ~~Tax~~of ~~Purposes~~operations onand ~~Their~~financial ~~Investment in the Partnership Without Receiving Any Cash Distributions From Us~~condition.

~~Star~~In ~~Gas~~2008 and ~~Partners~~continuing isinto afiscal ~~master~~2009, ~~limited~~economic ~~partnership~~conditions ~~and~~in ~~thus~~the ~~not~~United ~~subject~~States tohave ~~federal~~experienced ~~income~~a ~~taxes.~~downturn ~~Instead,~~due ~~our unitholders are required~~ to ~~report~~the ~~for~~sequential ~~federal~~effects ~~income~~of ~~tax~~the ~~purposes~~sub-prime ~~their~~lending ~~allocable~~crisis, ~~share~~general ofcredit ~~our~~market ~~income~~crisis, ~~gains,~~the ~~losses,~~general ~~deductions and~~unavailability ~~credits, regardless~~ of ~~whether~~financing, wecollateral effects ~~make~~on ~~cash~~the ~~distributions.~~finance Weand ~~expect~~banking ~~that~~industries, anvolatile ~~investor~~energy ~~will~~prices, beconcerns ~~allocated~~about ~~taxable~~inflation, ~~income~~slower ~~(mostly~~economic ~~dividend~~activity, ~~and~~decreased ~~interest~~consumer ~~income)~~confidence, ~~regardless~~reduced ofcorporate ~~whether~~profits aand ~~cash~~capital ~~distribution~~spending, ~~has~~adverse ~~been~~business ~~paid.~~conditions, ~~There will be no mandatory~~increased ~~distributions~~unemployment, ofliquidity ~~available~~concerns ~~cash~~and bydeclines usin tohousing ~~unitholders~~prices ~~through~~and ~~the~~house ~~fiscal quarter ending September 30, 2008~~sales.

~~Our~~Uncertainty ~~corporate~~about ~~subsidiary~~current economic ~~Star/Petro~~conditions ~~Inc.~~poses ~~and~~a ~~its~~risk ~~subsidiaries~~as ~~(“Star/Petro”)~~our ~~are~~customers ~~subject~~may postpone spending in response to ~~federal~~tighter credit, negative financial news and/or ~~state~~declines in income ~~taxes~~or asset values, which could have a material negative effect on the demand for the Partnership’s equipment and services and could lead to increased conservation and the possibility of certain of our customers seeking lower cost providers. ~~See~~Any increase in existing customers seeking lower cost providers and/or increase in the rejection ~~following~~rate ~~risk~~of ~~factor~~potential ~~regarding~~accounts could increase the Partnership’s overall rate of net ~~operating~~customer ~~loss~~attrition. ~~availability~~If adverse economic conditions persist, the Partnership could experience an increase in bad debts from financially distressed customers, which would have a negative effect on our liquidity, results of operations and financial condition.

AIn ~~change~~light inof ~~ownership~~the ~~for~~recent financial ~~Star~~turmoil, ~~Gas~~there ~~Partners~~can ~~may~~be ~~result~~no inassurance ~~the~~that ~~limitation of~~ the ~~potential~~lenders ~~utilization~~within ~~of net operating loss carryforwards by~~ our ~~corporate~~lending ~~subsidiary~~group ~~and~~will ~~our~~fund ~~ability~~a toborrowing ~~pay cash distributions~~request.

IfFrom time ~~Star Gas Partners were~~ to ~~experience~~time, ~~an “ownership change” under Section 382 of~~ the ~~Internal~~Partnership ~~Revenue~~borrows ~~Code~~to ofmeet ~~1986, as amended,~~ its ~~corporate~~seasonal ~~subsidiary,~~working ~~Star/Petro~~capital ~~may~~needs. beIn ~~materially~~light ~~restricted~~of in the ~~potential~~current ~~utilization~~financial ofturmoil ~~its~~affecting ~~net~~the ~~operating~~banking ~~loss~~system ~~carryforwards~~and tofinancial ~~offset~~markets, ~~future~~there ~~taxable~~can ~~income.~~be Ano ~~restriction~~assurances onthat ~~Star/Petro’s~~all ~~ability~~of tothe ~~use~~lending ~~its~~institutions ~~net operating loss~~within ~~carryforwards~~our tolending ~~reduce~~group ~~its~~will ~~federal~~have ~~taxable income would reduce~~ the ~~amount~~ability ~~of cash Star/Petro has available~~ to ~~make~~fund ~~distributions~~their topro ~~the~~rata ~~Partnership,~~portion ~~which would consequently reduce the amount~~ of ~~cash~~a ~~the~~borrowing ~~Partnership~~request. ~~has~~Our ~~available~~lending togroup ~~make distributions~~includes toJP ~~its~~Morgan ~~unitholders.~~Chase, AsBank of ~~September 30~~America, ~~2006~~RBS ~~Star/Petro~~Citizens, ~~had~~PNC aBank, ~~total~~Societe ~~federal~~Generale, ~~net~~Key ~~operating~~Bank, ~~loss~~TD ~~carryforward~~Banknorth, ofIsrael ~~$162.7~~Discount ~~million~~Bank, ofand RZB ~~which approximately $47~~Finance.9 ~~million were limited as a result of prior transactions.~~

The ~~continuation~~Partnership relies on the continued solvency of ~~high~~our ~~wholesale~~derivative ~~energy~~and ~~costs~~insurance ~~may~~counterparties. ~~adversely~~The Partnership ~~affect~~regularly uses derivative instruments such as futures, options, and swap agreements, in order to mitigate our ~~liquidity~~exposure to market risk associated with the purchase of home heating oil for our protected price customers, physical inventory on hand, inventory in transit and priced purchase commitments. The Partnership insures itself against catastrophic property and other losses with insurance companies.

~~Recent~~The ~~dynamics~~financial ofturmoil affecting the ~~heating~~banking ~~oil~~system ~~industry~~and ~~have~~financial markets ~~increased~~and ~~working~~the ~~capital~~possibility ~~requirements,~~that ~~principally~~financial ~~because~~institutions ~~high~~may ~~selling~~consolidate ~~prices~~or ~~require~~go ~~additional~~out ~~borrowing~~of tobusiness ~~finance~~have ~~accounts~~resulted ~~receivable~~in ~~and~~a ~~inventory.~~tightening ~~Under~~in ~~our~~the ~~revolving~~ credit ~~facility~~ markets, asa ~~amended,~~low welevel ~~may~~of ~~borrow~~liquidity upin tomany ~~$260~~financial ~~million~~markets, ~~which~~and extreme ~~increases~~volatility toin ~~$310~~fixed ~~million~~income, ~~during~~credit, ~~the~~currency ~~peak~~and ~~winter~~equity ~~months~~markets ~~from~~that ~~December~~may ~~through~~also ~~March~~adversely ofaffect ~~each~~the ~~year,~~Partnership’s ~~(subject~~results toof ~~borrowing~~operations ~~base~~and ~~limitations~~financial conditions. ~~and~~There could be a ~~coverage~~number ~~ratio)~~of ~~for~~follow-on ~~working capital~~effects ~~purposes~~from ~~subject~~the tocredit ~~maintaining~~crisis ~~availability~~on the ~~(as~~Partnership’s ~~defined~~business, including insolvency of key suppliers resulting in product ~~the~~delays ~~credit~~and ~~agreement)~~failure of ~~$25~~derivative ~~million~~counterparties orand aother financial ~~fixed~~institutions ~~charge~~negatively ~~coverage~~impacting ~~ratio~~the ofPartnership’s ~~not~~liquidity ~~less~~and ~~than~~financial 1condition.1 ~~to 1.0.~~

If counterparties to our ~~credit~~derivative ~~requirements~~instruments ~~should~~were ~~exceed~~to fail, the ~~amounts~~Partnership’s ~~available~~liquidity, ~~under~~results ~~our~~of ~~revolving~~operations ~~credit~~and ~~facility~~financial orcondition ~~should~~could be materially impacted, as we ~~fail~~would be obligated to ~~maintain~~fulfill our operational requirement of purchasing, storing and selling home heating oil, while losing the ~~required~~mitigating ~~availability~~benefits of economic hedges with a failed counterparty. If one of our insurance carriers should fail, the Partnership’s liquidity, results of operations and financial condition could be materially impacted, as we would ~~not~~have to fund any catastrophic loss. Currently, we have ~~sufficient~~outstanding ~~working~~derivative ~~capital~~instruments towith ~~operate~~the ~~our business~~following counterparties: Newedge USA, ~~which~~LLC, ~~could~~Cargill, ~~have~~Inc., aKey ~~material~~Bank ~~adverse~~National ~~effect~~Association, onJPMorgan ~~our~~Chase ~~financial~~Bank, ~~condition~~NA, Wachovia Bank, NA, Societe Generale, Bank of America, N.A., and ~~results~~RBS Sempra. Our primary insurance carrier is a subsidiary of ~~operations~~Chartis, formerly known as American International Group.

Our substantial debt and other financial obligations could impair our financial condition and our ability to fulfill our debt obligations.

We had total debt, exclusive of our working capital facility, of approximately $174 million as of September 30, 2006. Our substantial indebtedness and other financial obligations could:

• impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions or general corporate purposes;

Our substantial debt and other financial obligations could impair our financial condition and our ability to fulfill our debt obligations. Any refinancing of this substantial debt could be at significantly higher interest rates.

As of September 30, 2009, we had total debt, exclusive of borrowings under our revolving credit facility, of approximately $133.1 million. Our substantial indebtedness and other financial obligations could:

•

impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions or general corporate purposes;

•

have a material adverse effect on us if we fail to comply with financial and affirmative and restrictive covenants in our debt agreements and an event of default occurs as a result of a failure that is not cured or waived;

•

require us to dedicate a substantial portion of our cash flow for interest payments on our indebtedness and other financial obligations, thereby reducing the availability of our cash flow to fund working capital and capital expenditures;

•

limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; and

•

place us at a competitive disadvantage compared to our competitors that have proportionately less debt.

If we are unable to meet our debt service obligations and other financial obligations, we could be forced to restructure or refinance our ~~indebtedness~~ indebtedness and other financial transactions, seek additional equity capital or sell our assets. We might then be unable to obtain such financing or capital or sell our assets on satisfactory terms, if at all. Any refinancing of our indebtedness could be at significantly higher interest rates, and/or incur significant transaction fees.

Unitholders may have to report income for federal income tax purposes on their investment in the Partnership without receiving any cash distributions from us.

Star Gas Partners is a master limited partnership. Our unitholders are required to report for federal income tax purposes their allocable share of our income, gains, losses, deductions and credits, regardless of whether we make cash distributions. We expect that an investor will be allocated taxable income (mostly dividend, interest income and cancellation of indebtedness income) regardless of whether a cash distribution has been paid.

Our corporate subsidiary Star Acquisitions, Inc. and its subsidiaries (“Star Acquisitions”) are subject to federal and state income taxes. See the following risk factor regarding net operating loss availability.

A change in ownership of Star Gas Partners may result in the limitation of the potential utilization of net operating loss carry forwards by our corporate subsidiary may impact our ability to pay cash distributions.

If Star Gas Partners were to experience an “ownership change” under Section 382 of the Internal Revenue Code of 1986, as amended, its corporate subsidiary, Star Acquisitions (the Parent of Petro) may be materially restricted in the potential utilization of its net operating loss carry forwards to offset future taxable income. A restriction on Star Acquisitions’ ability to use its net operating loss carry forwards to reduce its federal taxable income would reduce the amount of cash Star Acquisitions has available to make distributions to the Partnership, which would consequently reduce the amount of cash the Partnership has available to make distributions to its unitholders.

As of the calendar tax year ended December 31, 2009, we anticipate that Star Acquisitions will have a federal net operating loss carry forward (“NOL”) of approximately $43.9 million. The 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% unitholders 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.

If the Partnership elects to be treated as a corporation for federal and state income tax purposes, such an election may result in adverse tax consequences to unitholders.

Currently, the Partnership’s main asset and source of income is an investment in Star Acquisitions. 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 the Partnership 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 the Partnership has all the administrative issues and costs associated with being a publicly traded partnership, but our unitholders do not currently receive any material tax benefits from this structure.

To reduce these administrative expenses and to rationalize our tax reporting structure, the Partnership is actively considering making an election sometime in calendar 2010 or thereafter to be treated as a corporation for federal and state income tax purposes. While the Partnership would still remain a publicly traded partnership for legal and governance purposes, for income tax purposes its unitholders will be treated as owning stock in a corporation rather than being partners in a partnership. Subsequent to the year of election the unitholders would receive annually Form 1099-DIV for any dividends and would no longer receive K-1s. In the year of election they would receive both, each form covering part of the year.

This election may have immediate short term tax implications as any unitholder who owns units at the time of the election would be deemed to have exchanged his units for shares in a “new” corporation, and to have received a certain amount of dividend income related to having had some share of the Partnership’s public debt assumed, as the new corporation would assume this liability.

Assuming that the Partnership’s taxable earnings and profits are equal to or less than the amount of distributions/dividends paid out during the year by the Partnership and the unitholder holds the units for the entire calendar year (or at least long enough during the year to receive a distribution(s) at least equal to the tax resulting from a share of dividend income reported on Form K-1), then most partners should not have any material negative cash flow consequences as a result of the Partnership making this election. Note that nothing herein should be interpreted as a projection of any future earnings amount or a projection or guarantee of future distributions or dividends.

In addition, there are risks that the Partnership could make this election and:

•

Not distribute or dividend enough cash to cover the taxes that may be due as a result of the dividend income generated by the election.

•

Even if distributions are made equal to the total taxable earnings of the Partnership, a particular unitholder could buy or sell units in a time period that might give rise to deemed dividend income caused by the election and not receive enough (or any) cash to offset the taxes due on such dividend income.

The Partnership intends to only make this election if it believes that it will have no overall material adverse impact on its 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, it will make this election is not determinable at this time. Unitholders are encouraged to consult their tax advisors with respect to these possible outcomes.

Since weather conditions may adversely affect the demand for home heating oil, our financial condition is vulnerable to warm winters.

Weather conditions have a significant impact on the demand for home heating oil because our customers depend on this product principally for space heating purposes. As a result, weather conditions may materially adversely impact our operating results and financial condition. During the peak-heating season of October through March, sales of home heating oil historically have represented approximately 75% to 80% of our annual home heating oil volume. Actual weather conditions can vary substantially from year to year or from month to month, significantly affecting our financial performance. Furthermore, warmer than normal temperatures in one or more regions in which we operate can significantly decrease the total volume we sell and the gross profit realized ~~on those sales~~ and, consequently, our results of operations. For example, in fiscal 2002 and fiscal 2006, temperatures were significantly warmer than normal for the areas in which we sell home heating oil, which adversely affected the amount of net income, EBITDA and Adjusted EBITDA (see Item 6. EBITDA and Adjusted EBITDA calculation) that we generated during these periods. In fiscal 2002, temperatures in our areas of operation were an average of 18.4% warmer than in fiscal 2001 and 18.0% warmer than normal. InTo ~~fiscal~~partially ~~2006,~~mitigate ~~temperatures~~the inadverse ~~our~~effect ~~areas~~ of ~~operation~~warm ~~were~~weather anon ~~average~~our ofcash ~~11.0%~~flows, ~~warmer~~we ~~than~~have inpurchased ~~fiscal~~a weather ~~2005~~hedge ~~and~~from ~~10.4%~~Swiss ~~warmer~~Re ~~than~~Financial ~~normal~~Products. ~~For~~We ~~fiscal~~will ~~2007,~~receive wea ~~have~~payment ~~purchased~~of $~~12.5~~35,000 per ~~million~~degree-day, inwhen ~~weather~~the ~~insurance to~~actual ~~help~~degree-days ~~minimize~~are ~~the~~less ~~adverse~~than ~~effect~~the of10 ~~weather~~year ~~volatility~~average onby ~~our cash flows~~7.5%. The ~~policy~~hedge covers the period from November 1, ~~2006~~2009 ~~to February~~through March 2831, ~~2007~~2010 taken as a whole. ~~However,~~and ~~there~~has ~~can~~a bemaximum nopayout ~~assurance that this insurance will be adequate to protect us from adverse effects~~ of ~~weather~~$12.5 ~~conditions~~million.

However, there can be no assurance that this hedge will be adequate to protect us from adverse effects of weather conditions or that we may be able to obtain similar protection in the future.

Our operating results will be adversely affected if we continue to experience significant net attrition in our home heating oil customer base.

Our net attrition rate of home heating oil customers for fiscal ~~2006~~2009, ~~2005~~2008, and ~~2004~~ 2007 was approximately 67.65%, 74.14%, and 65.40%, respectively. This rate represents the net of our annual gross customer losses after gross customer gains. For fiscal ~~2006~~2009, ~~2005~~2008, and ~~2004~~2007 we had gross customer losses of 1921.60%, 2019.1%, and 1917.56%, respectively, which were partially offset by gross customer gains during these periods of 13.5%, 1214.97%, and 1312.16%, respectively. The gain of a new customer does not fully compensate for the loss of an existing customer because of the expenses incurred during the first year to acquire a new customer ~~and the higher attrition rate associated with new customers~~. Customer losses are the result of various factors, including but not limited to:

•

price competition;

•

customer relocations;

• credit ~~problems~~worthiness; and

• ~~quality~~conversions ~~of service issues, including those related~~ to ~~our~~natural ~~centralized call center~~gas.

The continuing unprecedented ~~rise and~~ volatility in the price of heating oil has intensified price competition and added to our difficulty in reducing net customer attrition. ~~We believe our attrition rate has risen not only because of increased price competition related to the rise in oil prices but also because of operational problems.~~

High net customer attrition rates may continue through fiscal 2007 and perhaps beyond and even to the extent the rate of attrition can be halted, attrition from prior fiscal years will adversely impact net income in the future.

For additional information about customer attrition, See Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Customer Attrition.”

9Because of the highly competitive nature of the home heating oil business, we may not be able to retain existing customers or acquire new customers, which would have an adverse impact on our operating results and financial condition.

~~Table~~Our home heating oil business is subject to substantial competition. Most of ~~Contents~~our district locations compete with numerous distributors, primarily on the basis of reliability of service, price, and response to customer needs. Each district location operates in its own competitive environment.

~~Sudden~~We compete with distributors offering a broad range of services and ~~sharp~~prices, from full-service distributor, like ourselves, to those offering delivery only. Like many companies in the home heating oil ~~price~~business, ~~increases~~we ~~that~~provide ~~cannot~~home beheating ~~passed~~equipment repair service on a 24-hour-a-day, seven-day-a-week, 52 weeks a year basis. We believe that this tends to build customer loyalty. In some instances homeowners have formed buying cooperatives that seek to purchase fuel oil from distributors at a price lower than individual customers are ~~may~~otherwise ~~adversely~~able ~~affect~~to ~~our~~obtain. ~~operating~~We ~~results~~also compete for retail customers with suppliers of alternative energy products, principally natural gas, propane and electricity.

~~The~~If ~~retail~~we ~~home~~are ~~heating~~unable ~~oil industry is a “margin-based” business in which gross profit depends on the excess of retail sales prices over supply costs. Consequently, our profitability is sensitive~~ to ~~changes~~compete ~~in the wholesale price of home heating oil caused by changes in supply or other market conditions. These factors are beyond our control and thus~~effectively, ~~when there are sudden and sharp increases in the wholesale cost of home heating oil,~~ we may ~~not~~lose beexisting ~~able to pass on these increases to~~ customers ~~through increased retail sales prices. Wholesale price increases could reduce our gross profits and could, if continuing over an extended period of time reduce demand by encouraging conservation~~ or ~~conversion~~fail to ~~alternative~~acquire ~~energy sources. In an effort to retain existing accounts and attract~~ new customers, wewhich ~~may~~would ~~offer~~have ~~discounts,~~a ~~which~~material ~~will~~adverse ~~impact~~effect ~~the~~on ~~net~~our ~~per~~operating ~~gallon~~results ~~gross margin~~and ~~realized.~~financial condition.

A significant portion of our home heating oil volume is sold to price-protected customers and our gross margins could be adversely affected if we are not able to effectively hedge against fluctuations in the volume and cost of product sold to these customers.

A significant portion of our home heating oil volume is sold to individual customers under an agreement pre-establishing the maximum sales price or a fixed price of home heating oil over a 12-month period. For the fiscal years ended September 30, 2006 and 2005, approximately 38% and 48%, respectively, of the total home heating oil volume sold was under a price-protected plan. We currently purchase futures contracts, swaps and option contracts for a substantial majority of the heating oil that we expect to sell to these price-protected customers when the customer renews his purchase commitment for the next 12 months. We generally get a signed agreement or a voice recording from these price-protected customers acknowledging the fixed or maximum price per gallon. The amount of home heating oil volume that we hedge per price-protected customer is based upon the estimated fuel consumption per 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 be less than the hedged volume we may have excess inventory on hand at unfavorable costs. Currently, none of our derivative instruments qualify for hedge accounting treatment. Therefore, to the extent we continue to have derivative instruments that do not qualify for hedge accounting treatment, we could experience great volatility in earnings as these currently outstanding derivative contracts are marked to market. The Partnership is currently evaluating whether to elect hedge accounting for future periods.

If we do not make acquisitions on economically acceptable terms, our future growth will be limited.

The home heating oil industry is not a growth industry because new housing generally ~~does~~uses ~~not~~natural ~~use~~gas ~~oil~~when ~~heat~~it ~~and~~is ~~increased~~available, and competition has ~~exists~~also increased from alternative energy sources. Accordingly, future growth will depend on our ability to make acquisitions at attractive prices. We cannot assure that we will be able to identify attractive acquisition candidates in the home heating oil sector in the future or that we will be able to acquire businesses on economically acceptable terms. Factors that may adversely affect home heating oil operating and financial results may limit our access to capital and adversely affect our ability to make acquisitions. Under the terms of our revolving credit facility, our most restrictive agreement, as long as we maintain certain financial ratios, we are ~~restricted~~not ~~from~~limited ~~making~~on ~~any~~the number of individual ~~acquisition~~acquisitions inor ~~excess~~aggregate dollar amount of ~~$10.0~~acquisitions ~~million~~we ~~and~~make in any fiscal year, ~~may~~but ~~not~~we ~~exceed~~are anrestricted ~~aggregate~~from making any individual acquisition in excess of $25.0 million, ~~unless~~without ~~waived~~the lenders’ approval. In addition, ~~the~~to ~~Partnership~~make isan ~~restricted~~acquisition, ~~from~~the ~~making~~Partnership ~~any~~is ~~acquisition~~required ~~unless~~to ~~availability~~have Availability (~~essentially~~as ~~borrowing~~defined ~~base~~in ~~availability~~the ~~less~~credit ~~borrowings~~agreement) ~~would~~ beof ~~at least~~ $40.0 million, on a historical pro forma ~~basis,~~and ~~during the last 12~~forward-~~month~~looking ~~period ending on the date of such acquisition~~basis. ~~These~~This ~~restrictions~~covenant restriction may limit our ability to make acquisitions. Any acquisition may involve potential risks to us and ultimately to our unitholders, including:

•

an increase in our indebtedness;

• an increase in our working capital requirements;

•

our inability to integrate the operations of the acquired business;

•

our inability to successfully expand our operations into new territories;

•

the diversion of management’s attention from other business concerns;

•

an excess of customer loss or loss of key employees from the acquired business; and

• the assumption of additional liabilities including environmental liabilities.

10In addition, acquisitions may be dilutive to earnings and distributions to unitholders, and any additional debt incurred to finance acquisitions may among other things, affect our ability to make distributions to our unitholders.

Increases in home heating oil prices beyond current levels may have adverse effects on our business, financial condition and results of operations.

Increases in home heating oil prices beyond current levels may have adverse effects on our business, financial condition and results of operations, including the following:

•

higher bad debt expense as a result of higher selling prices;

•

higher interest expense as a result of increased working capital borrowing to finance higher receivables and/or inventory balances; and

•

reduced liquidity as a result of higher receivables and/or inventory balances as the Partnership must fund a portion of any increase in receivables, inventory and hedging costs from its own resources thereby tying up funds that would otherwise be available for other purposes.

The volatility in wholesale energy costs may adversely affect our liquidity.

Our business requires a significant investment in working capital to finance accounts receivable and inventory during the heating season. Under our revolving credit facility, we may borrow up to $240 million, which increases to $290 million during the peak winter months from December through April of each year (subject to borrowing base limitations and a coverage ratio) for working capital purposes subject to maintaining availability (as defined in the credit agreement) of $43.5 million or a fixed charge coverage ratio of not less than 1.10x.

If increases in home heating oil costs cause our working capital requirements to exceed the amounts available under our revolving credit facility or should we fail to maintain the required availability, we would not have sufficient working capital to operate our business, which could have a material adverse effect on our financial condition and results of operations.

We generally utilize forward swaps with members of our lending group to manage market risk associated with our fixed price customers, our physical inventory and fuel we use for our vehicles. These institutions have not required an initial cash margin deposit or any mark to market maintenance margin for these swaps. Any mark to market exposure is reserved against our borrowing base and can thus reduce the amount available to us under our revolving credit facility. The mark to market reserve against our borrowing base for swap derivative instruments with our lending group was $4.7 million as of September 30, 2009 and $6.5 million as of November 30, 2009.

For our ceiling price customers and some of our fixed price customers, we purchase call options, which usually requires the Partnership to pay an up front cash payment. This reduces our liquidity, as we must pay for the option before any sales are made to the customer.

For certain of our supply contracts, we are required to establish the purchase price in advance of receiving the physical product. This occurs at the end of the month and is usually no more than 20 days prior to receipt of the product. We use futures contracts or swaps to “short” the purchase commitment such that the commitment floats with the market. As a result, any upward movement in the market for home heating oil would reduce our liquidity, as we would be required to post additional cash collateral for a futures contract or our availability to borrow under our bank facility would be reduced in the case of a swap. At December 31, 2009, we expect to have approximately 40 million gallons of purchase commitments and physical inventory shorted with a futures contract or swap. Assuming a $1.00 per gallon increase in price, our near term liquidity would be reduced by $40 million.

For the majority of our fiscal year, the amount of cash received from customers with a balanced payment plan is greater than actual billings. This amount is reflected on the balance sheet under the caption “customer credit balances.” At September 30, 2009, customer credit balances aggregated $74.2 million. Generally, customer credit balances are at their low point after the end of the heating season and at their peak prior to the beginning of the heating season. We have approximately 133,000 customers, or 34% of our residential customer base, on the balanced payment plan. If home heating oil prices increased and we failed to recalculate the balanced payments to reflect current heating oil prices, our liquidity could also be reduced.

InSudden ~~addition,~~and ~~acquisitions~~sharp ~~may~~oil beprice ~~dilutive~~increases tothat ~~earnings~~cannot ~~and~~be ~~distributions~~passed toon ~~unitholders and any additional debt incurred~~ to ~~finance~~customers ~~acquisitions~~ may ~~among~~adversely ~~other things,~~ affect our operating ~~ability to make distributions to our unitholders~~results.

~~Because~~The ofretail ~~the~~home ~~highly~~heating oil industry is a “margin-based” business in which gross profit ~~competitive~~depends ~~nature~~on the excess of retail sales prices per gallon over supply costs per gallon. Consequently, our profitability is sensitive to changes in the ~~retail~~wholesale price of home heating oil ~~industry~~caused by changes in supply or other market conditions. These factors are beyond our control and thus, when there are sudden and sharp increases in the wholesale cost of home heating oil, we may not be able to ~~retain~~pass ~~existing~~on these increases to customers orthrough ~~acquire~~increased retail sales prices. In an effort to retain existing accounts and attract new customers, ~~which~~we ~~would~~may ~~have~~offer andiscounts, ~~adverse~~which will impact onthe ~~our~~net ~~operating~~per ~~results~~gallon ~~and~~gross ~~financial~~margin ~~condition~~realized.

IfA significant portion of our home heating oil ~~business~~volume is ~~unable~~sold to ~~compete~~price-protected ~~effectively,~~customers we(ceiling ~~may~~and ~~lose~~fixed) ~~existing~~and ~~customers~~our orgross ~~fail~~margins tocould ~~acquire~~be ~~new~~adversely ~~customers,~~affected ~~which~~if ~~would~~we ~~have~~are ~~a material~~not ~~adverse~~able ~~effect~~to oneffectively ~~our~~hedge ~~results~~against offluctuations ~~operations~~in the volume and ~~financial~~cost ~~condition~~of product sold to these customers.

WeA ~~can~~significant ~~make~~portion noof ~~assurances~~our ~~that~~home weheating ~~will~~oil bevolume ~~able~~is sold to ~~compete~~individual customers ~~successfully~~under an arrangement pre-establishing the ceiling sales price or a fixed price of home heating oil over a fixed period. IfWhen ~~competitors~~the ~~continue~~customer tomakes ~~increase~~a ~~market~~purchase ~~share~~commitment byfor ~~reducing~~the ~~their~~next ~~prices~~period we currently purchase option contracts, asswaps and futures contracts for a substantial majority of the heating oil that we ~~believe~~expect ~~occurred~~to ~~recently~~sell to these price-protected customers. The amount of home heating oil volume that we hedge per price-protected customer is based upon the estimated fuel consumption per average customer, ~~our~~per ~~operating~~month. ~~results~~In ~~and~~the ~~financial~~event ~~condition~~that the actual usage exceeds the amount of the hedged volume on a monthly basis, we could be ~~materially~~required ~~and~~to ~~adversely~~obtain ~~affected~~additional volume at unfavorable margins. WeIn ~~also~~addition, ~~compete~~should ~~for~~actual ~~customers~~usage ~~with~~in any month be ~~suppliers~~less ofthan ~~alternative~~the ~~energy~~hedged ~~products~~volume, ~~principally~~(including, ~~natural~~for ~~gas~~example, as a result of early terminations by fixed price customers) our hedging losses could be greater. WeCurrently, ~~face~~the ~~competition~~Partnership ~~from~~has ~~electricity~~elected not to designate its derivative instruments as hedging instruments under FASB ASC 815-10-05 Derivatives and ~~natural~~Hedging ~~gas.~~topic ~~Over~~(SFAS 133), and the ~~past~~change ~~five~~in ~~years~~fair value of the derivative instruments are recognized in our statement of operations. Therefore, ~~customer~~we ~~conversions~~could ~~from~~experience ~~heating~~great ~~oil~~volatility in earnings as these currently outstanding derivative contracts are marked to ~~natural~~market ~~gas~~and ~~have~~non-cash ~~averaged~~gains ~~approximately~~or ~~1% per~~losses ~~year~~are recorded in the statement of operations.

~~The~~Significant ~~continuing~~declines ~~unprecedented rise~~ in the wholesale price of home heating oil ~~has~~may ~~intensified~~cause protected price ~~competition,~~customers ~~and~~to ~~added~~renegotiate toor ~~our~~terminate ~~difficulty~~their inarrangements ~~reducing customer~~which ~~attrition~~may asadversely ~~consumers~~impact ~~become~~our ~~more~~gross ~~price~~profit ~~sensitive~~and net income.

~~Energy~~When ~~efficiency~~the wholesale price of home heating oil declines significantly after a customer enters into a protected price arrangement with us, some customers elect to renegotiate their arrangement in order to enter into a lower cost pricing plan with us or terminate their arrangement and ~~new~~switch ~~technology~~to ~~may~~a ~~reduce~~competitor. As a result of significant decreases in the ~~demand~~price ~~for~~of ~~our~~home ~~products~~heating ~~and~~oil ~~adversely~~following the ~~affect~~summer of 2008, many protected price customers decided to renegotiate their agreements with us in fiscal 2009. It is our ~~operating~~policy ~~results~~to bill a termination fee when customers terminate their arrangement with us. It is our belief that approximately 10,000 customers chose another supplier as a result of being billed the termination fee.

Increased conservation and technological advances, including installation of improved insulation and the development of more efficient furnaces and other heating devices, have adversely affected the demand for our products by retail customers. Future conservation measures or technological advances in heating, conservation, energy generation or other devices might reduce demand and adversely affect our operating results.

We are subject to operating and litigation risks that could adversely affect our operating results whether or not covered by insurance.

Our operations are subject to all operating hazards and risks normally incidental to handling, storing, transporting and otherwise providing customers with ~~home~~our ~~heating oil~~products. As a result, we may be a defendant in legal proceedings and litigation arising in the ordinary course of business.

We maintain insurance policies with insurers in amounts and with coverage and deductibles asthat we believe are reasonable. However, there can be no assurance that this insurance will be adequate to protect us from all material expenses related to potential future claims for remediation costs and personal and property damage or that these levels of insurance will be available in the future at economical prices.

Our operations are subject to operational hazards and our insurance reserves may not be adequate to cover actual losses.

We self-insure ~~a portion of~~ workers’ compensation, automobile and general liability claims. Weup to ~~establish~~pre-established ~~reserves~~limits. ~~based~~In ~~upon~~storing ~~expectations~~and asdelivering product to ~~what~~ our ~~ultimate~~customers, ~~liability~~our ~~will~~operations beare ~~for~~subject ~~these~~to ~~claims~~operational ~~using~~hazards ~~our~~such ~~historical~~as ~~developmental~~natural ~~factors.~~disasters, Weadverse ~~evaluate~~weather, onaccidents, anfires, ~~annual~~explosions, ~~basis~~hazardous ~~the~~materials ~~potential~~releases, ~~for~~mechanical failures ~~changes~~and inother ~~loss~~events ~~estimates~~beyond ~~with~~our ~~the~~control. ~~support~~If any of ~~qualified~~these ~~actuaries.~~events Aswere ofto ~~September 30~~occur, ~~2006,~~ we ~~had approximately~~could ~~$38.8~~incur ~~million~~substantial oflosses ~~insurance~~because ~~reserves~~of ~~and~~personal ~~had~~injury ~~issued~~or ~~$47.8~~loss ~~million in letters~~ of ~~credit~~life, ~~for~~severe ~~current~~damage to and ~~future~~destruction ~~claims. The ultimate settlement~~ of ~~these~~property ~~claims~~and ~~could~~equipment, ~~differ~~and ~~materially~~pollution ~~from~~or ~~the assumptions used to calculate the reserves,~~other ~~which~~environmental ~~could~~damage ~~have~~resulting ain ~~material~~curtailment ~~effect~~or onsuspension of our ~~results~~related of operations.

We13 ~~are the subject of a number of class action lawsuits alleging violation of the federal securities laws, which if decided adversely, could have a material adverse effect on our financial condition.~~

On September 23, 2005, defendants filed motions to dismiss the consolidated amended complaint for failure to state a claim under the federal securities laws and failure to satisfy the applicable pleading requirements of the Private Securities Litigation Reform Act of 1995 (“PSLRA”), and the Federal Rules of Civil Procedure. On August 21, 2006, the court issued its rulings on defendants’ motions to dismiss, granting the motions and dismissing the consolidated amended complaint in its

~~entirety.~~We Onestablish ~~August 23,~~reserves ~~2006,~~based ~~the~~upon ~~court~~expectations ~~entered~~as ato ~~judgment~~what ofour ~~dismissal.~~ultimate Onliability ~~September 7,~~will ~~2006,~~be ~~the plaintiffs moved~~ for claims ~~reconsideration~~using ~~and~~our ~~to alter~~historical ~~and~~developmental ~~reopen~~factors. ~~the~~We ~~court’s~~evaluate ~~August 23,~~on ~~2006~~an ~~judgment~~annual ofbasis ~~dismissal~~the ~~and~~potential for ~~leave~~changes toin ~~file~~loss aestimates ~~second~~with ~~consolidated~~the ~~amended~~support ~~complaint~~of qualified actuaries. OnAs ~~October~~of September 2030, ~~2006~~2009, ~~defendants~~we ~~filed~~had ~~their~~approximately ~~memorandum~~$34.8 million of ~~law~~insurance reserves inand ~~opposition~~had toissued ~~the plaintiffs’ motion~~$37.4 ~~Plaintiffs~~million ~~filed~~in ~~their~~letters ~~reply~~of ~~brief~~credit onfor orcurrent ~~about~~and ~~November 20,~~future ~~2006~~claims. The ~~matter~~ultimate issettlement ~~now~~of ~~under~~these ~~consideration~~claims bycould ~~the~~differ ~~court.~~materially Infrom the ~~interim,~~assumptions ~~discovery~~used ~~in the matter remains stayed pursuant~~ to ~~the~~calculate ~~mandatory stay provisions of~~ the ~~PSLRA.~~reserves, ~~While no~~which ~~prediction~~could ~~may~~have bea ~~made~~material aseffect toon ~~the~~our results ~~outcome~~ of ~~litigation, we intend to defend against this class action vigorously~~operations.

In the event the above action is decided adversely to us, it could have a material adverse effect on our results of operations, financial condition and liquidity.

Our results of operations and financial condition may be adversely affected by governmental regulation and associated environmental and regulatory costs.

The home heating oil business is subject to a wide range of federal and state laws and regulations related to environmental and other ~~regulated~~ matters. We have implemented environmental programs and policies designed to avoid potential liability and costs under applicable environmental laws. It is possible, however, that we will experience increased costs due to stricter pollution control requirements or liabilities resulting from noncompliance with operating or other regulatory permits. New environmental regulations might adversely impact operations, including underground storage and transportation of home heating oil. In addition, there are environmental risks inherently associated with home heating oil operations, such as the risks of accidental release or spill. It is possible that material costs and liabilities will be incurred, including those relating to claims for damages to property and persons.

In addition, our results of operations and ability to issue distributions may be negatively impacted by significant changes in federal and state tax law.

Proposed legislation concerning the regulation of greenhouse gases and other issues that impact the Partnership’s operations could, if adopted, increase the Partnership’s costs and/or require changes to its operations, which could have a material adverse effect on the Partnership’s financial condition and results of operations.

There is increasing attention in the United States and worldwide concerning the issue of climate change and the effect of emissions of greenhouse gases, in particular from the combustion of fossil fuels. There are efforts to develop new federal proposals by Congress and the EPA that could lead to the adoption of a mandatory program to reduce greenhouse gas emissions through, for example, an economy-wide cap-and-trade program, a carbon tax or a combination of both. Debate continues on the direction, scope and timing of U.S. policy on the regulation of greenhouse gas emissions. It is probable that any regulatory program that caps emissions or imposes a carbon tax will increase costs for the Partnership and its customers which could lead to increased conservation or customers seeking lower cost alternatives. However, at this time an estimate of such costs to comply with potential national, regional or state greenhouse gas emissions reduction legislation, regulations or initiatives is not possible because these programs and proposals are in the early stages of development and any final program, if adopted, could vary from current proposals.

There is also pending legislation directed at over-the-counter derivatives that is considering the establishment of position limits in the energy market. While this legislation is in its early stages, passage of over-the-counter derivative position limits would affect the Partnership’s liquidity, expose it to greater counterparty credit risk and contribute to earnings volatility, as the Partnership would have to alter its heating oil hedging program, and concentrate positions to the derivatives that would be available at fewer select counterparties.

Furthermore, laws and regulations that affect the Partnership’s operations continue to evolve at both the state and federal levels, which may ultimately add compliance costs to the Partnership. Changes in regulations under different political administrations, the imposition of additional regulations, or the enactment of new legislation that impacts employment, labor, trade, transportation or logistics, health care, tax or environmental issues could have the potential of materially impacting our financial condition or results of operations.

The Partnership will continue to monitor and evaluate federal, regional or state programs and proposals and judicial and administrative decisions that could affect our customers or operations.

Energy efficiency and new technology may reduce the demand for our products and adversely affect our operating results.

Conflicts of interest have arisen and could arise in the future as a result of relationships between the general partner and its affiliates on the one hand, and the Partnership and its limited partners, on the other hand.

Conflicts of interest have arisen and could arise in the future as a result of relationships between the general partner and its affiliates, on the one hand, and the Partnership or any of the limited partners, on the other hand. As a result of these conflicts the general partner may favor its own interests and those of its affiliates over the interests of the unitholders. The nature of these conflicts is ongoing and includes the following considerations:

•

The general partner’s affiliates are not prohibited from engaging in other business or activities, including direct competition with us.

•

The general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings and reserves, each of which can impact the amount of cash, if any, available for distribution to unitholders, and available to pay principal and interest on debt.

•

The general partner controls the enforcement of obligations owed to the Partnership by the general partner.

•

The general partner decides whether to retain separate counsel or others to perform services for the Partnership.

•

In some instances the general partner may borrow funds in order to permit the payment of distributions to unitholders.

•

The general partner may limit its liability and reduce its fiduciary duties, while also restricting the remedies available to unitholders for actions that might, without limitations, constitute breaches of fiduciary duty. Unitholders are deemed to have consented to some actions and conflicts of interest that might otherwise be deemed a breach of fiduciary or other duties under applicable state law.

•

The general partner is allowed to take into account the interests of parties in addition to the Partnership in resolving conflicts of interest, thereby limiting its fiduciary duty to the unitholders.

•

The general partner determines whether to issue additional units or other securities of the Partnership.

•

The general partner determines which costs are reimbursable by us.

•

The general partner is not restricted from causing us to pay the general partner or its affiliates for any services rendered on terms that are fair and reasonable to us or entering into additional contractual arrangements with any of these entities on our behalf.

The risk of global terrorism and political unrest may adversely affect the economy and the price and availability of home heating oil and have a material adverse effect on our business, financial condition, and results of operations.

Terrorist attacks and political unrest may adversely impact the price and availability of home heating oil, our results of operations, our ability to raise capital and our future growth. The impact that the foregoing may have on the heating oil industry in general, and on our business in particular, is not known at this time. An act of terror could result in disruptions of crude oil supplies and markets, the source of home heating oil, and its facilities could be direct or indirect targets. Terrorist activity may also hinder our ability to transport home heating oil if our normal means of transportation become damaged as a result of an attack. Instability in the financial markets as a result of terrorism could also affect our ability to raise capital. Terrorist activity could likely lead to increased volatility in prices for home heating oil. Insurance carriers are routinely excluding coverage for terrorist activities from their normal policies, but are required to offer such coverage as a result of new federal legislation. We have opted to purchase this coverage with respect to our property and casualty insurance programs. This additional coverage has resulted in additional insurance premiums.

The impact of hurricanes and other natural disasters could cause disruptions in supply and have a material adverse effect on our business, financial condition and results of operations.

Hurricanes, particularly in the Gulf of Mexico, and other natural disasters may cause disruptions in the supply chains for home heating oil and other ~~petroleum~~ products that we sell. Disruptions in supply could have a material adverse effect on our business, financial condition and results of operations, causing an increase in wholesale prices and decrease in supply.

Cash distributions (if any) are not guaranteed and may fluctuate with performance and reserve requirements.

~~There~~Distributions ~~will be no mandatory distributions~~ of available cash by us ~~through~~to ~~the~~unitholders ~~fiscal quarter ending September 30, 2008. Thereafter, distributions on the common units~~ will depend on the amount of cash generated, and distributions may fluctuate based on our performance. The actual amount of cash that is available will depend upon numerous factors, including:

•

profitability of operations;

• required principal and interest payments on debt or debt prepayments;

•15 ~~debt covenants~~

•

debt covenants;

•

margin account requirements;

•

cost of acquisitions;

•

issuance of debt and equity securities;

•

fluctuations in working capital;

•

capital expenditures;

•

adjustments in reserves;

•

prevailing economic conditions;

• financial, business and other factors; ~~and~~

• increased pension funding requirements;

• ~~preserving~~the amount of our net operating loss ~~carryforwards~~carry forwards; and

•

federal, state and local corporate income and franchise taxes.

Most of these factors are beyond the control of the general partner.

The partnership agreement gives the general partner discretion in establishing reserves for the proper conduct of our business, including acquisitions. These reserves will also affect the amount of cash available for distribution.

The revolving credit facility and the indenture for the senior notes both impose certain restrictions on our ability to pay distributions to unitholders. The most restrictive covenant is found in the Partnership’s revolving credit facility. Under the terms of our credit facility, the Partnership must have 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 the Partnership to have a fixed charge coverage ratio of 1.25x. (See Note 11-Long-Term Debt and Bank Facility Borrowings)

ITEM 1B.

UNRESOLVED STAFF COMMENTS

Not applicable.

ITEM 2.

PROPERTIES

We provide services to our customers in the Northeast and Mid-Atlantic regions of the United States from 1925 ~~principle~~principal operating locations and 46 depots, 2826 of which are owned and 3745 of which are leased~~, in 31 marketing areas in the Northeast and Mid-Atlantic regions of the United States~~. As of September 30, ~~2006~~2009, we had a fleet of ~~918 truck~~845 truck and transport vehicles, the majority of which were owned and 1,~~177~~012 service vans, the majority of which ~~are~~were leased. We lease our corporate headquarters in Stamford, Connecticut. Our obligations under our credit facility are secured by liens ~~and~~ and mortgages on substantially all of the Partnership’s and subsidiaries real and personal property.

ITEM 3.

LEGAL PROCEEDINGS—LITIGATION

On or about October 21, 2004, a purported class action lawsuit on behalf of a purported class of unitholders was filed against the Partnership and various subsidiaries and officers and directors in the United States District Court of the District of Connecticut entitled Carter v. Star Gas Partners, L.P., et. al., No. 3:04-cv-01766-IBA, et. al. Subsequently, 16 additional class action complaints, alleging the same or substantially similar claims, were filed in the same district court collectively referred to herein as the “Class Action Complaints”). The class actions were consolidated into one ~~consolidated~~action entitled In re Star Gas Securities Litigation, No 3:04cv1766 (JBA). The class action plaintiffs generally alleged that the Partnership violated Sections 10(b) and 20(a) of the Securities Exchange Act of 1934, as amended, and Rule 10b-5 promulgated thereunder. On August 23, 2006, the court entered a judgment of dismissal dismissing the consolidated amended complaint in its entirety. The court subsequently denied plaintiffs’ motion to modify the judgment to grant leave to amend the complaint and other relief.

On ~~September~~August 2320, ~~2005~~2009, ~~defendants filed motions to dismiss~~ the ~~consolidated~~Second ~~amended~~Circuit ~~complaint~~issued ~~for failure to state~~ a ~~claim~~Summary ~~under~~Order ~~the~~affirming ~~federal securities laws and failure to satisfy the applicable pleading requirements of the Private Securities Litigation Reform Act of 1995~~ (~~“PSLRA”~~1)~~, and the Federal Rules of Civil Procedure. On August~~ ~~21, 2006,~~ the ~~court~~District ~~issued its rulings on defendants~~Court’s ~~motions~~order ~~to dismiss, granting the motions and~~ dismissing the ~~consolidated~~class ~~amended~~action ~~complaint~~with inprejudice ~~its~~and ~~entirety. On August~~(2) ~~23, 2006,~~ the ~~court~~District ~~entered a judgment of dismissal. On September 7, 2006, the plaintiffs moved for reconsideration and to alter and reopen the court~~Court’s ~~August 23, 2006 judgment of dismissal and for leave to file a second~~ ~~consolidated~~order ~~amended~~denying ~~complaint. On October 20, 2006, defendants filed their memorandum of law in opposition to the~~ plaintiffs’ motion. ~~Plaintiffs~~to ~~filed~~modify ~~their reply brief on or about November 20, 2006. The matter is now under consideration by~~ the ~~Court.~~judgment Into ~~the~~grant ~~interim,~~leave ~~discovery~~to inamend the ~~matter~~complaint ~~remains~~and ~~stayed~~other ~~pursuant to the mandatory stay provisions of the PSLRA~~relief. ~~(See Note 22)~~

Our 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 propane and home heating oil. As a result, at any given time we are a defendant in various legal proceedings and litigation arising in the ordinary course of business. We maintain insurance policies with insurers in amounts and with coverages and deductibles we believe are reasonable and prudent. However, we cannot assure that this insurance will be adequate to protect us 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 addition, the occurrence of an explosion may have an adverse effect on the public’s desire to use our products. In the opinion of management, except as described above 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. (See Note 22 – Commitments and Contingencies)

ITEM 4.

SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None.

1416

PART II

ITEM 5.

MARKET FOR REGISTRANT’S UNITS AND RELATED MATTERS

The common units, representing common limited partner interests in the Partnership, are listed and traded on the New York Stock Exchange, Inc. (“NYSE”) under the symbol “SGU”.

The following tables set forth the high and low closing price ranges for the common units ~~for~~and the ~~fiscal~~cash ~~2006~~distribution ~~and 2005 quarters indicated. There were no~~declared ~~cash~~on ~~distributions~~each ~~declared~~unit onfor the ~~common~~fiscal ~~units~~2009 ~~during~~and ~~these~~2008 ~~periods~~quarters indicated.

	SGU – Common Unit Price Range								Distributions Declaredper Unit
	High				Low
	FiscalYear2006		FiscalYear2005		FiscalYear2006		FiscalYear2005
	FiscalYear2009		FiscalYear2008		FiscalYear2009		FiscalYear2008		FiscalYear2009		FiscalYear2008
Quarter Ended
December 31,	$	2.3940	$	224.2382	$	1.0583	$	43.3262	$	—	$	—
March 31,	$	2.9771	$	73.2297	$	12.8422	$	32.1179	$	0.0675	$	—
June 30,	$	23.9862	$	43.1145	$	2.2670	$	12.9455	$	0.0675	$	—
September 30,	$	23.6271	$	32.6490	$	23.2426	$	2.3905	$	0.0675	$	—

As of September 30, ~~2006~~2009, there were approximately ~~533~~500 holders of record of common units.

There is no established public trading market for the Partnership’s 0.3 million general partner units.

Partnership Distribution Provisions

~~There~~Commencing ~~will~~with bethe ~~no mandatory~~fiscal ~~distributions~~quarter ofended ~~available~~December 31, ~~cash~~2008, bywe usare required to ~~the~~make ~~holders~~distributions ofin an amount equal to our ~~common~~Available ~~units~~Cash, ~~and~~as ~~general~~defined ~~partner~~in ~~units~~our ~~through~~Partnership Agreement, no more than 45 days after the end of each fiscal quarter, ~~ending~~to ~~September 30,~~holders ~~2008~~of record on the applicable record dates. ~~Beginning~~Available ~~October 1~~Cash, ~~2008~~as defined in our Partnership Agreement, ~~minimum~~generally ~~quarterly~~means ~~distributions~~all cash on hand at the ~~common units~~end ~~will~~of ~~start~~the ~~accruing~~relevant atfiscal quarter less the ~~rate~~amount of cash ~~$0.0675~~reserves ~~per~~established ~~quarter~~by ~~($0.27~~the onBoard anof ~~annual~~Directors ~~basis)~~of our general partner in its reasonable discretion for future cash requirements. ~~The~~These ~~information~~reserves ~~concerning~~are ~~restrictions~~established onfor the proper conduct of our business, including acquisitions, the payment of debt principal and interest, for distributions ~~required~~during bythe ~~Item 5.~~next four quarters and to comply with applicable laws and the terms of ~~this~~any ~~report~~debt isagreements ~~incorporated~~or byother ~~reference~~agreement to ~~Note~~which 6we ~~Quarterly~~are ~~Distribution~~subject. The Board of Directors of our general partner reviews the level of Available Cash, ofeach ~~the~~quarter ~~Partnership’s~~based ~~consolidated~~upon ~~financial~~information ~~statements~~provided by management.

~~The~~According ~~revolving~~to ~~credit~~the ~~facility~~terms ~~and~~of our partnership agreement, minimum quarterly distributions on the ~~indenture~~common ~~for~~units accrue at the ~~new~~ ~~notes~~rate ~~both~~of ~~impose~~$0.0675 ~~certain~~per ~~restrictions~~quarter ($0.27 on ~~our~~an ~~ability~~annual tobasis). ~~pay~~The information concerning restrictions on distributions required by Item 5. of this report is incorporated by reference to ~~unitholders~~Note 5. Quarterly Distribution of Available Cash, of the Partnership’s consolidated financial statements.

~~Tax~~The ~~Matters~~revolving credit facility and the indenture for the notes both impose certain restrictions on our ability to pay distributions to unitholders. The most restrictive covenant is found in the Partnership’s revolving credit facility. Under the terms of our credit facility, the Partnership must have 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 the Partnership to have a fixed charge coverage ratio of 1.25x.

~~Star~~17 Gas Partners is a master limited partnership and thus not subject to federal and state income taxes. The corporate subsidiaries wholly owned by Star Gas Partners are subject to federal and state income taxes at the corporate level. Our unitholders are required to report for income tax purposes their allocable share of our income, gains, losses, deductions and credits, regardless of whether we make distributions. We expect that an investor will be allocated taxable income regardless of whether a cash distribution has been paid.

Common Unit Repurchase and Retirement

On July 21, 2009, the Board of Directors of the Partnership’s General Partner authorized the repurchase of up to 7.5 million of the Partnership’s common units. 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. 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 Units Purchased as Part of a Publicly Announced Plan or Program		Average Price Paid per Unit		Maximum Number (or approximate Dollar Value) of Units that May Yet Be Purchased Under the Plans or Programs
July 2009	—		$	—	7,500
August 2009	160		$	3.59	7,340
September 2009	477		$	3.69	6,863

Fiscal year 2009 total	637		$	3.67	6,863

October 2009	3,072	(1)	$	3.97	3,791
November 2009	350		$	3.96	3,441

(1)	October 2009 common unit repurchases include 2.7 million common units acquired in a private sale.

ITEM 6.

SELECTED HISTORICAL FINANCIAL AND OPERATING DATA

The selected financial data as of September 30, ~~2006~~2009 and ~~2005~~2008, and for the years ended September 30, ~~2006~~2009, ~~2005~~2008 and ~~2004~~2007 is derived from the financial statements of the Partnership included elsewhere in this Report. The ~~Consolidated~~ ~~Financial~~selected ~~Statements~~financial ~~for~~data ~~the~~as ~~years~~of ~~ended~~ September 30, ~~2005~~2007, 2006 and ~~2004~~2005 ~~have~~and ~~been~~for ~~restated.~~the ~~See~~years ~~Note~~ended ~~2 to Consolidated Financial Statements. The selected financial data as of~~ September 30, ~~2004,~~2006 ~~2003~~ and ~~2002~~2005 is derived from financial statements of the Partnership not included elsewhere in this Report. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

	Fiscal Years Ended September 30,
(in thousands, except per unit data)	~~2006~~2009			~~2005~~2008			~~2004~~2007			~~2003(e)~~2006			~~2002(d)(e)~~2005
				(restated, see note 2)			(restated, see note 2)			(restated)			(restated)
Statement of Operations Data:
Sales	$	1,~~296~~206,~~512~~813		$	1,~~259~~543,~~478~~093		$	1,~~105~~267,~~091~~175		$	1,~~102~~296,~~968~~512		$	~~790~~1,~~378~~259,478
Costs and expenses:
Cost of sales		1875,~~014,908~~755			~~983~~1,~~732~~257,592			~~797~~981,~~330~~559			~~793~~1,~~134~~014,565			~~549~~983,~~841~~732
Change in the fair value of derivative instruments		45,677			(6,081	)		(25,811	)		5,299			(13,939	)
(Increase) decrease in the fair value of derivative instruments		(13,690	)		25,467			(15,664	)		45,677			(6,081	)
Delivery and branch expenses		~~205~~222,~~037~~740			~~231~~211,~~581~~868			~~232~~197,~~985~~513			~~217~~203,~~244~~535			~~174~~231,~~030~~086
Depreciation and amortization expenses		3219,~~415~~406			3526,~~480~~784			3728,~~313~~995			3532,~~535~~415			4035,~~444~~480
General and administrative expenses		2122,~~673~~480			4318,~~190~~077			19,~~537~~661			3923,~~413~~518			1743,~~515~~685
Goodwill impairment charge		—			~~67,000~~—			—			—			—67,000
Operating income (loss)		~~(23~~80,~~198~~122	)		~~(95~~3,~~424~~305	)		4355,~~737~~111			12(23,~~343~~198	)		22(95,~~487~~424	)
Interest expense, net		~~(21~~13,~~203~~637	)		~~(31~~13,~~838~~808	)		~~(36~~11,~~682~~525	)		~~(29~~21,~~530~~203	)		~~(23~~31,~~843~~838	)
Amortization of debt issuance costs		(2,~~438~~750	)		(2,~~540~~339	)		(32,~~480~~282	)		(2,~~038~~438	)		(12,~~197~~540	)
Gain (loss) on redemption of debt		(6,603	)		(42,082	)		—			212			—
(Gain) loss on redemption of debt		(9,706	)		—			—			6,603			42,082
Income (loss) from continuing operations before income taxes		~~(53~~73,~~442~~441	)		(~~171~~12,~~884~~842	)		341,~~575~~304			(1953,~~013~~442	)		(2171,~~553~~884	)
Income tax expense (benefit)		~~477~~(57,597	)		~~696~~566			12,~~240~~002			~~1,200~~477			~~(1,700~~696	)
Income (loss) from continuing operations		~~(53~~131,~~919~~038	)		(~~172~~13,~~580~~408	)		239,~~335~~302			(2053,~~213~~919	)		(~~853~~172,580	)
Income (loss) from discontinued operations, net of income taxes		—			(6,189	)		22,176			19,523			507
Loss from discontinued operations, net of income taxes		—			—			—			—			(6,189	)
Gain (loss) on sales of discontinued operations, net of income taxes		—			~~157,560~~—			(~~538~~1,061	)		—			—157,560
Cumulative effects of changes in accounting principles for discontinued operations - Adoption of SFAS No. 142		—			—			—			(3,901	)		—
Income (loss) before cumulative effects of changes in accounting principle for continuing operations		131,038			(13,408	)		38,241			(53,919	)		(21,209	)
Income (loss) before cumulative effects of changes in accounting principle for continuing operations		(53,919	)		(21,209	)		23,973			(4,591	)		(346	)
Cumulative effects of changes in accounting principles-change in inventory pricing method		—			—			—			(344	)		—
Cumulative effects of changes in accounting principles-change in inventory pricing method		(344	)		—			—			—			—
Net income (loss)	$	131,038		$	(13,408	)	$	38,241		$	(54,263	)	$	(21,209	)
Net income (loss)	$	(54,263	)	$	(21,209	)	$	23,973		$	(4,591	)	$	(346	)
Weighted average number of limited partner units:
Basic		5275,~~944~~738			3575,~~821~~774			3575,~~205~~774			3252,~~659~~944			2835,~~790~~821
Diluted		5275,~~944~~738			3575,~~821~~774			3575,~~205~~774			3252,~~767~~944			2835,821

1619

	Fiscal Years Ended September 30,
(in thousands, except per unit data)	~~2006~~2009			~~2005~~2008			~~2004~~2007			~~2003(e)~~2006			~~2002(d)(e)~~2005
				(restated,see note 2)			(restated,see note 2)			(restated)			(restated)
Per Unit Data:
Basic and diluted loss from continuing operations per unit (a)	$	(1.01	)	$	(4.77	)	$	0.07		$	(0.61	)	$	(0.40	)
Basic and diluted income (loss) from continuing operations per unit (a)	$	1.43		$	(0.18	)	$	0.51		$	(1.01	)	$	(4.77	)
Basic and diluted net income (loss) per unit (a)	$	(1.0243	)	$	(0.5918	)	$	0.6750		$	(01.1402	)	$	(0.159	)
Cash distribution declared per common unit	$	—0.2025		$	—		$	~~2.30~~—		$	~~2.30~~—		$	~~2.30~~—
Cash distribution declared per senior sub. unit	$	—		$	—		$	1.73		$	1.65		$	1.65
Cash distribution declared per junior sub. unit	$	—		$	—		$	—		$	1.15		$	1.15
Cash distribution declared per general partner unit	$	—		$	—		$	—		$	1.15		$	1.15
Balance Sheet Data (end of period):
Current assets	$	~~295~~376,~~880~~898		$	~~305~~344,~~319~~299		$	~~228~~320,~~053~~503		$	~~204~~295,~~417~~880		$	~~214~~305,~~648~~319
Total assets	$	~~581~~664,~~208~~126		$	~~623~~605,~~148~~433		$	~~954~~602,~~858~~104		$	~~968~~581,~~918~~208		$	~~936~~623,~~213~~148
Long-term debt	$	~~174~~133,~~056~~112		$	~~267~~173,~~417~~752		$	~~503~~173,~~668~~941		$	~~499~~174,~~341~~056		$	~~396~~267,~~733~~417
Partners’ Capital	$	~~173~~306,~~325~~334		$	~~145~~199,~~108~~977		$	~~169~~216,~~771~~331		$	~~189~~173,~~776~~325		$	~~232~~145,~~264~~108
Summary Cash Flow Data:
Net Cash provided by (used in) operating activities	$	1878,~~364~~455		$	~~(54~~71,~~915~~555	)	$	1351,~~669~~115		$	1518,~~365~~364		$	18(54,~~773~~915	)
Net Cash provided by (used in) investing activities	$	(37,~~271~~568	)	$	~~467~~(5,~~431~~488	)	$	6(29,~~447~~254	)	$	(483,~~395~~271	)	$	~~(12~~467,~~381~~431	)
Net Cash provided by (used in) financing activities	$	(2354,~~120~~535	)	$	(~~306,694~~145	)	$	(~~19,874~~96	)	$	48(23,~~049~~120	)	$	28(306,~~135~~694	)
Other Data:
Earnings from continuing operations before interest, taxes, depreciation and amortization (EBITDA) (b)(c)	$	2,614		$	(102,026	)	$	81,050		$	48,090		$	62,931
Earnings from continuing operations before net interest expense, income taxes, depreciation and amortization (EBITDA) (b)	$	109,234		$	30,089		$	84,106		$	2,614		$	(102,026	)
Retail gallons sold		389,920			487,300			551,612			567,024			457,749
Adjusted EBITDA (b)	$	85,838		$	55,556		$	68,442		$	54,894		$	975
(a) Income (loss) from continuing operations per unit is computed by dividing the limited partners’ interest in income (loss) from continuing operations by the weighted average number of limited partner units outstanding. Net income (loss) per unit is computed by dividing the limited partners’ interest in net income (loss) by the weighted average number of limited partner units outstanding. (b) EBITDA was reduced (increased) by the following:
Retail gallons sold		349,385			351,128			376,645			389,920			487,300
	2006			2005			2004			2003			2002
				(restated,see note 2)			(restated,see note 2)			(restated)			(restated)
Change in the fair value of derivative instruments	$	45,677		$	(6,081	)	$	(25,811	)	$	5,299		$	(13,939	)
(Gain) loss on redemption of debt		6,603			42,082			—			(212	)		—
Goodwill impairment charge		—			67,000			—			—			—
Total	$	52,280		$	103,001		$	(25,811	)	$	5,087		$	(13,939	)

(ca) ~~EBITDA~~Income (loss) from continuing operations ~~should~~per ~~not~~unit beis ~~considered~~computed asby andividing ~~alternative~~the tolimited ~~net~~partners’ ~~income~~interest ~~(as~~in anincome ~~indicator of operating performance~~(loss) orfrom ascontinuing anoperations ~~alternative~~by tothe ~~cash~~weighted ~~flow~~average ~~(as~~number ~~a measure~~ of ~~liquidity~~limited orpartner ~~ability~~units tooutstanding. ~~service~~Net ~~debt~~income ~~obligations~~(loss), ~~but~~per ~~provides~~unit ~~additional~~is ~~information~~computed ~~for~~by ~~evaluating~~dividing ~~our ability to make~~ the ~~minimum~~limited ~~quarterly~~partners’ ~~distribution.~~interest ~~The~~in ~~working~~net ~~capital~~income ~~facility~~(loss) ~~and~~by the ~~senior~~weighted ~~secured~~average ~~notes,~~number ~~impose certain restrictions on our ability to pay distributions to unitholders. See Item 5 “Market for Registrant’s Units and Related Matters” with respect to the provisions~~ of ~~our~~limited ~~partnership~~partner ~~agreement~~units ~~that govern the payment of distributions~~outstanding.

17(b) 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;

•

our operating performance and return on invested capital as 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.

Adjusted EBITDA is calculated as 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. Management believes the presentation of this measure is relevant and useful because it allows investors to view the Partnership’s performance in a manner similar to the method management uses, and makes it easier to compare its results with other companies that have different financing and capital structures. In addition, this measure is consistent with the manner in which the Partnership’s debt covenants in its material debt agreements are calculated. Both the Partnership’s 10.25% Senior Note agreement and its bank credit facility contain covenants that restrict equity distributions, acquisitions, and the amount of debt it can incur. Under the most restrictive of these covenants, which is found in the bank credit facility, the agent bank could step in and control all cash transactions for the Partnership if we failed to comply with the minimum availability or the fixed charge coverage ratio. The Partnership is required to maintain 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 of 1.1x (Adjusted EBITDA being a significant component of this calculation). This method of calculating Adjusted EBITDA may not be consistent with that of other companies and should be viewed in conjunction with measurements that are computed in accordance with GAAP.

~~The~~Each ~~definition~~ of “EBITDA” ~~set~~and ~~forth~~Adjusted ~~above~~EBITDA ~~may~~has beits ~~different~~limitations ~~from~~as ~~that~~an ~~used~~analytical bytool, ~~other~~and ~~companies.~~it should ~~EBITDA~~not ~~from~~be ~~continuing~~considered ~~operations~~in isisolation ~~calculated~~or as a substitute for analysis of our results as reported under GAAP. Some of the ~~fiscal~~limitations ~~years~~of ~~ended~~EBITDA ~~September 30~~and asAdjusted ~~follows~~EBITDA are:

(in thousands)	2006			2005			2004		2003			2002
				(restated,see note 2)			(restated,see note 2)		(restated)			(restated)
Loss from continuing operations	$	(53,919	)	$	(172,580	)	$	2,335	$	(20,213	)	$	(853	)
Plus:
Income tax expense (benefit)		477			696			1,240		1,200			(1,700	)
Amortization of debt issuance cost		2,438			2,540			3,480		2,038			1,197
Interest expense, net		21,203			31,838			36,682		29,530			23,843
Depreciation and amortization		32,415			35,480			37,313		35,535			40,444
EBITDA from continuing operations	$	2,614		$	(102,026	)	$	81,050	$	48,090		$	62,931

•

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

~~(d)~~• ~~Our~~Although ~~results~~depreciation ~~for~~and ~~fiscal~~amortization ~~year~~are ~~ended~~non-cash ~~September 30~~charges, ~~2002~~the assets being depreciated or amortized often will have to be replaced and EBITDA and Adjusted EBITDA do not reflect the ~~impact~~cash ofrequirements ~~the~~for ~~provisions~~such ~~of SFAS No. 142.~~replacements;

~~(e)~~• ~~Fiscal~~EBITDA ~~2003~~ and ~~fiscal~~Adjusted ~~2002~~EBITDA ~~have~~do ~~been~~not ~~restated~~reflect ~~with~~changes ~~respect~~in, toor ~~the~~cash ~~accounting~~requirements for, ~~derivative~~our ~~transactions~~working ~~and~~capital ~~the calculation of pension expense.~~requirements;

~~ITEM~~• 7.EBITDA ~~MANAGEMENT’S~~and ~~DISCUSSION~~Adjusted ~~AND~~EBITDA ~~ANALYSIS~~do OFnot ~~FINANCIAL~~reflect ~~CONDITION~~the ~~AND~~cash ~~RESULTS~~necessary OFto ~~OPERATIONS.~~make payments of interest or principal on our indebtedness; and

•

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

EBITDA and Adjusted EBITDA is calculated for the fiscal years ended September 30 as follows:


(in thousands)	2009			2008			2007			2006			2005
Income (loss) from continuing operations	$	131,038		$	(13,408	)	$	39,302		$	(53,919	)	$	(172,580	)
Plus:
Income tax expense (benefit)		(57,597	)		566			2,002			477			696
Amortization of debt issuance cost		2,750			2,339			2,282			2,438			2,540
Interest expense, net		13,637			13,808			11,525			21,203			31,838
Depreciation and amortization		19,406			26,784			28,995			32,415			35,480

EBITDA from continuing operations		109,234			30,089			84,106			2,614			(102,026	)
(Increase)/decrease in the fair value of derivative instruments		(13,690	)		25,467			(15,664	)		45,677			(6,081	)
(Gain) loss on redemption of debt		(9,706	)		—			—			6,603			42,082
Goodwill impairment charge		—			—			—			—			67,000

Adjusted EBITDA		85,838			55,556			68,442			54,894			975

Add/(subtract)
Income tax (expense) benefit		57,597			(566	)		(2,002	)		(477	)		(696	)
Interest expense, net		(13,637	)		(13,808	)		(11,525	)		(21,203	)		(31,838	)
Unit compensation income		—			—			—			—			(2,185	)
Provision for losses on accounts receivable		10,310			11,961			5,726			6,105			9,817
(Increase) decrease in accounts receivables		26,657			(28,002	)		5,761			(3,809	)		(13,845	)
(Increase) decrease in inventories		(17,747	)		41,368			(8,222	)		(23,830	)		(18,248	)
Increase (decrease) in customer credit balances		(11,964	)		13,390			(3,724	)		8,576			11,360
Change in deferred taxes		(61,355	)		—			—			—			—
Change in other operating assets and liabilities		2,756			(8,344	)		(3,341	)		(1,892	)		(10,255	)

Net cash provided by (used in) operating activities	$	78,455		$	71,555		$	51,115		$	18,364		$	(54,915	)

Net Cash provided by (used in) investing activities	$	(7,568	)	$	(5,488	)	$	(29,254	)	$	(3,271	)	$	467,431

Net Cash provided by (used in) financing activities	$	(54,535	)	$	(145	)	$	(96	)	$	(23,120	)	$	(306,694	)

ITEM 7.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Statement Regarding Forward-Looking Disclosure

This Annual Report on Form 10-K 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, the consumption patterns of our customers, our ability to obtain satisfactory gross profit margins, our ability to obtain new accounts and retain existing accounts, our ability to ~~effect~~make strategic acquisitions ~~or redeploy assets~~, the impact of litigation, ~~the continuing impact of the business process redesign project and~~ our ability to ~~address issues related to that project, 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 environmental, health, and safety regulations, the ability to attract and retain employees, customer credit worthiness, ~~and~~counter party credit worthiness, marketing plans, and general economic conditions. 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. 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 ~~have~~be ~~been~~ 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 Initiatives and Strategy.” Without limiting the foregoing , the words “believe,” “anticipate,” “plan,” “expect,” “seek,” “estimate” and similar expressions are intended to identify forward-looking statements. Important factors that could cause actual results to differ materially from our expectations (“Cautionary Statements”) are disclosed in this Annual Report on Form 10-K. 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 operations of the Partnership and its subsidiaries, and should be read in conjunction with the description of our business in Item 1. “Business” and the historical Financial and Operating Data and Notes thereto included elsewhere in this Report. ~~We completed the sale of our propane segment in December 2004 and the following discussion reflects the historical results for the propane segment as discontinued operations.~~

~~Restatement~~In fiscal 2008, we completed our transition from a centralized customer service model to a more traditional customer service model in which the majority of our customer service calls are answered locally. We have implemented an employee-staffed centralized call center to augment our internal staffing requirements for certain overflow, off-peak and weekend hours.

On December 13, 2006, one day before the planned filing of the Partnership’s annual report, the Partnership’s external auditors, KPMG, made the Partnership aware of a speech given by a professional accounting fellow of the Securities and Exchange Commission (“SEC”) on December 11, 2006 relating to Statement of Financial Accounting Standards “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”). After reviewing the speech, the Partnership conducted an extensive review of its accounting for derivative transactions under SFAS 133 to determine whether the Partnership’s documentation for certain derivative transactions met the strict requirements of SFAS 133 to permit hedge accounting and the deferral of unrecognized non-cash gains and losses for such transactions. The documentation was consistent with the documentation previously used by the Partnership and provided to KPMG in support of hedge accounting treatment for similar transactions that had been reflected in prior period financial statements. However, SFAS 133 is a very complex and highly technical standard, which has been the subject of an evolving interpretation by the accounting community. After further review, on December 26, 2006 the Partnership, the Audit Committee and the Board of Directors, determined that the Partnership’s accounting for derivative transactions did not comply with the technical requirements of SFAS 133 to qualify for hedge accounting.

As a result, the Partnership determined that it was necessary to amend and restate its financial statements for each of the fiscal years ended September 30, 2005 and 2004 as well as the Partnership’s quarterly reports for the periods ended June 30, 2006, March 31, 2006, December 31, 2005, September 30, 2005, June 30, 2005, March 31, 2005 and December 31, 2004 with respect to the accounting and disclosures for certain derivative transactions under SFAS 133. In addition, prior to June 30, 2006, the Partnership did not include the amortization of an unrecognized gain in the calculation of pension expense resulting in an overstatement of pension expense for fiscal year’s 1999 to 2005 of $1.7 million. The Partnership has restated our results to record the amortization of the unrecognized gain. See Note 2 to our Consolidated Financial Statements for further details on the restatement. The Partnership has discussed this matter with KPMG, who served as the Partnership’s external auditors for all affected periods, in reaching the conclusion to restate the financial statements.

The restatement does not impact the economics of the hedge transactions nor does it affect the Partnership’s liquidity, cash flow from operating activities in any historical or future period, or the amount of available cash to pay distributions as defined in the Partnership agreement in any historical or future period. The hedges were primarily entered into in order to mitigate the Partnership’s exposure to market risk associated with the purchase of home heating oil for its price-protected customers.

The Partnership has been contacted informally by the Boston District Office of the SEC requesting the voluntary provision of documents and related information concerning the Partnership’s use of derivatives and hedge accounting. The SEC has advised the Partnership that the inquiry should not be construed as an indication by the SEC or its staff that any violations of the law have occurred, nor should it be considered a reflection upon any person, entity or security. The Partnership is fully cooperating with this inquiry.

Recapitalization

Effective as of April 28, 2006, the Partnership completed its recapitalization pursuant to the terms of a unit purchase agreement dated as of December 5, 2005, as amended, by and among, the Partnership, Star Gas LLC (the former general partner), Kestrel and its wholly-owned subsidiaries, Kestrel Heat (the new general partner) and KM2, LLC, a Delaware limited liability company. (See Note 3 to the Consolidated Financial Statements - Recapitalization)

Seasonality

InThe ~~analyzing our financial results, 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 results in the sale of approximately 30% of our volume of home heating oil in the first fiscal quarter and 45% of our volume in the second fiscal quarter of each fiscal year, the peak heating season. WeIn ~~generally~~addition, ~~realize~~sales ~~net~~volume typically ~~income~~fluctuates from year to year in ~~the~~response ~~first~~to variations in weather, wholesale energy prices and other factors.

18Degree 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 Hedge Contract—Warm Weather

Weather conditions have a significant impact on the demand for home heating oil because our customers depend on this product principally for heating purposes. Actual weather conditions can vary substantially from year to year, significantly affecting our financial performance. To partially mitigate the adverse effect of warm weather on our cash flows,

~~second~~we ~~fiscal~~have ~~quarters~~purchased ~~and~~a ~~net~~warm ~~losses~~weather ~~during~~hedge ~~the~~from ~~third~~Swiss ~~and~~Re ~~fourth~~Financial ~~fiscal quarters~~Products. InUnder ~~addition,~~this ~~sales~~hedge ~~volume~~agreement, ~~typically~~we ~~fluctuates~~will ~~from~~receive ~~year~~a topayment ~~year~~of ~~in response~~$ to35,000 per ~~variations~~heating ~~in weather~~degree-day, ~~wholesale~~when ~~energy~~the ~~prices~~total ~~and~~number ~~other~~of heating ~~factors.~~degree-days ~~Gross~~in ~~profit~~the isperiod ~~not~~covered ~~only~~is ~~affected~~less bythan ~~weather~~92.5% ~~patterns~~of ~~but~~the ~~also~~10-year ~~by changes in customer mix~~average. InThe ~~addition,~~hedge ~~our~~covers ~~gross~~the ~~profit~~period ~~margins~~from ~~vary~~November 1, by2009 ~~geographic~~through ~~region. Accordingly~~March 31, ~~gross~~ ~~profit~~2010 ~~margins~~taken ~~could~~as ~~vary~~a ~~significantly~~whole ~~from~~and ~~year~~has ~~to year in~~ a ~~period~~maximum payout of ~~identical~~$ ~~sales~~12.5 ~~volumes~~million.

Per Gallon Gross Profit Margins

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

A significant portion of our home heating oil volume is sold to individual customers under an arrangement pre-establishing the ceiling sales price or a fixed price of home heating oil over a fixed period. When these price-protected customers agree to purchase home heating oil from us for the next heating season, we will purchase option contracts, swaps and futures contracts for a substantial majority of the heating oil that we expect to sell to these customers. The amount of home heating oil volume that we hedge per price-protected customer is based upon the estimated fuel consumption per average customer, per month. In the event that the actual usage exceeds the amount of the hedged volume on a monthly basis, we 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

~~SFAS~~FASB ~~No.~~ASC 815-10-05 Derivatives and Hedging topic (FAS 133), 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. Currently, ~~none~~the Partnership has elected not to designate its derivative instruments as hedging instruments under this standard, and, as a result, the changes in fair value of ~~our~~the derivative instruments ~~have~~are ~~been~~recognized ~~designated~~in ~~for~~our ~~hedge~~statement ~~accounting~~of ~~treatment~~operations. Therefore, we ~~could~~ experience great volatility in earnings as outstanding ~~these~~home ~~currently~~heating ~~outstanding~~oil derivative instruments are marked to market~~. To~~ ~~the~~and ~~extent~~non-cash ~~that~~gains and losses are recorded prior to the ~~partnership~~sale ~~continues~~of the commodity to ~~have~~the ~~derivative~~customer. ~~instruments~~To ~~that~~the doextent ~~not~~that ~~qualify~~the ~~for~~Partnership ~~hedge~~continues this accounting treatment, the volatility in any given period related to unrealized non-cash gains or losses on derivative home heating oil instruments can be significant to the overall results of the Partnership,. ~~however~~However, we ultimately expect those gains and losses to be offset by ~~when~~the ~~they~~cost ~~become~~of ~~realized.~~product ~~The~~when ~~Partnership is currently evaluating whether to elect hedge accounting in future periods~~purchased.

~~Home~~Impact ~~Heating~~on ~~Oil~~Liquidity ~~Price~~of Wholesale Product Cost Volatility

The wholesale price of home heating oil has been extremely volatile over the last ~~three~~several ~~fiscal~~ years. ~~and~~Our ~~has~~liquidity ~~resulted~~is inadversely ~~increased~~impacted ~~consumer~~in ~~awareness~~ times of increasing heating ~~costs~~oil ~~and~~prices, ~~increased~~as ~~net~~the ~~customer~~Partnership ~~attrition.~~must ~~Like~~use ~~any~~cash ~~other~~to ~~market~~pay ~~commodity,~~for ~~the~~its ~~price~~hedging ofrequirements ~~home~~and ~~heating oil~~to isfund ~~subject~~a toportion of the ~~economic~~increased ~~forces~~levels of ~~supply~~accounts receivable and ~~demand~~inventory. ~~Rapid~~Our ~~global~~liquidity ~~economic expansion~~ is ~~fueling~~also anadversely ~~ever-increasing~~impacted ~~demand~~at ~~for~~times ~~oil.~~by ~~The~~sudden and ~~price~~sharp ofdecreases ~~home~~in heating oil isprices ~~closely~~due ~~linked~~ to the ~~price~~increased ~~refiners~~margin ~~pay~~requirements for ~~crude~~futures ~~oil~~contracts ~~which~~and iscollateral ~~the~~requirements ~~principal cost~~for ~~component~~swaps ofthat ~~home~~we ~~heating~~use ~~oil.~~to ~~Crude~~manage ~~oil~~market isrisks ~~bought~~related ~~and~~to ~~sold~~our infixed ~~the~~price ~~international~~customers ~~marketplace~~ and asphysical ~~such~~inventory isthat ~~significantly~~are not ~~affected~~immediately offset by ~~the~~lower ~~economic~~inventory ~~forces~~and ofaccounts ~~worldwide~~receivable ~~supply~~carrying ~~and demand~~costs.

WeIncome ~~have~~Taxes—Valuation ~~seen~~Allowance ~~home~~and ~~heating~~Net ~~oil price movements ranging from $0.54 to $1.00 per gallon over the last three fiscal years. In a volatile market even small changes in supply~~Operating orLoss ~~demand~~Carry ~~can~~Forward dramatically affect prices. Heating oil prices are subject to price fluctuations if demand rises sharply because of excessively cold weather and/or disruptions at refineries and instability in key oil producing regions.

~~Customer~~Based ~~Attrition~~upon a review of a number of factors, including historical operating performance and our expectation that we could generate sustainable consolidated taxable income for the foreseeable future, we concluded at the end of fiscal 2009 that the majority of the Partnership’s net deferred tax assets should be recognized. Thus, pursuant to FASB ASC 740-10 Income Taxes topic (FAS 109), we recorded a tax benefit during fiscal 2009 reversing a majority of the opening valuation allowance, resulting in a non-cash increase in net income of $86.4 million. This benefit was offset by a current income tax expense of $3.8 million and deferred income tax expense of $25.0 million related to current year activity (including net operating loss carry forward utilization), resulting in a net income tax benefit of $57.6 million.

~~For~~Most ~~fiscal~~of ~~2006,~~the ~~we lost 29,600 accounts (net) or 6~~$86.6%4 ofmillion ~~our~~benefit ~~home~~relating ~~heating oil customer base, as compared~~ to ~~fiscal~~the ~~2005~~valuation inallowance ~~which~~release werelated ~~lost 35,100 accounts (net) or 7.1% of our home heating oil customer base. This decrease in net customers lost of 5,500 was due~~ to ~~fewer~~federal ~~gross customer gains (5,600)~~ and ~~less~~state ~~gross~~loss ~~customer~~carry ~~losses~~forwards (~~11,100~~NOLs)~~. In fiscal 2006~~, insurance 26reserves,~~200~~ ofand the ~~homes~~net weoperating ~~serviced~~book ~~changed ownership compared to 34,200 homes in the prior year. In 2006, we were able to retain 13,600 of those homes~~ versus ~~15,800 retained~~tax intiming ~~fiscal 2005. Gross gains were negatively impacted by (i) the continuation~~ of ~~our~~intangible higher minimum profitability standards for new customers, (ii) a reduction in mass-market advertising, which attracted more transient customers in the past, (iii) continued customer price sensitivity due to the increased level and volatility of energy prices and (iv) increased minimum credit standards for customersamortization.

InAt ~~addition~~December 31, to2004, ~~the~~we had ~~reduction~~federal inNOLs ~~gross~~of ~~losses~~$170.6 ~~due~~million toand ~~moves~~at inDecember 31, ~~fiscal 2006~~2009, we ~~also~~anticipate ~~experienced~~that ~~fewer~~these ~~losses~~NOLs ~~relating~~will be reduced to ~~price~~approximately (2$43.9 million. Over this five year period,~~500),~~ ~~service~~we will have utilized $26.9 million of federal NOLs on average each year to ~~(1,000) and~~offset ~~other~~our ~~factors~~taxable income. We expect that over the next few years, we will utilize the

~~For~~23 fiscal 2005, we lost approximately 35,100 accounts (net) or 7.1% of our home heating oil customer base, as compared to fiscal 2004 in which we lost 33,100 accounts (net) or 6.4%. This increased loss of 2,000 accounts was largely due to the factors described above as well as our ability to retain existing homes that changed hands worsened by over 4,000 accounts. Losses of protected price accounts also increased. Certain of these accounts that were renewed at a low fixed price and per gallon margin in the summer and fall of 2004 chose not to renew as we sought higher prices and higher per gallon margins in fiscal 2005.

Gross customer gains and gross customer losses

	Fiscal Year Ended
Description	2006		2005		2004
Gross Customer Gains	58,200		63,800		67,400
Gross Customer Losses	(87,800	)	(98,900	)	(100,500	)
Net Customer Loss	(29,600	)	(35,100	)	(33,100	)

~~Net~~ majority ~~customer~~of ~~attrition~~the asremaining aNOLs. ~~percent~~After we exhaust the NOLs, the amount of cash taxes that we will pay will increase significantly and will reduce the ~~home~~annual ~~heating~~amount ~~oil~~of ~~customer~~cash ~~base~~available for distribution to unitholders. For example, in calendar 2006, 2007, and 2008 we paid federal cash taxes of $0.1 million, $1.0 million and $0.6 million, respectively. If we did not have the NOLs available to us for calendar 2006, 2007 and 2008, our federal cash taxes would have increased to $2.6 million, $17.2 million and $11.1 million for calendar 2006, 2007 and 2008, respectively.

	Fiscal Year Ended
Description	2006		2005		2004
Gross Customer Gains	13.0	%	12.9	%	13.1	%
Gross Customer Losses	(19.6	)%	(20.0	)%	(19.5	)%
Net Customer Attrition	(6.6	)%	(7.1	)%	(6.4	)%

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

~~During~~Currently, the Partnership’s ~~three~~main ~~months~~asset ~~ended~~and ~~September 30,~~source ~~2006,~~of weincome ~~lost~~is ~~5,500~~an ~~accounts~~investment ~~(net)~~in orStar 1Acquisitions, Inc.2% ofOur ~~our home~~unitholders ~~heating~~do ~~oil~~not ~~customer~~receive ~~base,~~any asof ~~compared~~the totax ~~the~~benefits ~~three~~normally ~~months~~associated ~~ended~~with ~~September 30,~~owning ~~2005~~units in ~~which~~a wepublicly ~~lost~~traded 15partnership,~~800~~ ~~accounts~~as ~~(net)~~any orcash ~~3.2%~~coming offrom Star ~~its~~Acquisitions ~~home~~to ~~heating~~the ~~oil~~Partnership ~~customer~~will ~~base.~~generally ~~This~~have ~~reduction~~been intaxed ~~net~~first ~~losses~~at ofa ~~10,300~~corporate ~~accounts~~level ~~was~~and ~~due~~then tomay ~~an increase~~also inbe ~~gross~~taxable ~~customer~~to ~~gains~~our ofunitholders 1as dividends,~~300~~ ~~accounts~~reported ~~and~~via aannual ~~reduction~~Forms inK-1. ~~customer~~The ~~losses~~production of ~~9,000~~the ~~accounts~~Forms asK-1 ~~losses~~themselves ~~due~~is toan ~~pricing~~expensive and ~~declined~~administratively byintensive ~~approximately~~process. 6Thus,~~000~~ ~~accounts and~~ the ~~number~~Partnership ofhas ~~customer~~all ~~homes~~the ~~changing~~administrative ~~hands~~issues ~~declined~~and bycosts ~~3,600.~~associated Inwith ~~the fourth~~being ~~quarter~~a ~~of 2006~~large, wepublicly ~~retained~~traded ~~40%~~partnership, ofbut ~~those~~our ~~homes~~unitholders ~~compared~~do tonot ~~33%~~currently inreceive ~~the~~any ~~same~~material ~~period~~tax inbenefits ~~2005~~from this structure.

~~Net~~To ~~home~~reduce ~~heating~~these ~~oil~~administrative ~~customers~~expenses ~~accounts~~and to better rationalize our tax reporting structure, the Partnership is ~~(lost)~~actively byconsidering ~~quarter~~making an election sometime in calendar 2010 or thereafter, to be treated as a corporation for federal and state income tax purposes. While the Partnership would still remain a publicly traded partnership for legal and governance purposes, for income tax purposes its 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 K-1’s. In the year of election unitholders would receive both, each form covering part of the year.

Quarter Ended	Fiscal 2006		Fiscal 2005		Fiscal 2004
December 31	(7,200	)*	(2,000	)	(3,300	)
March 31	(10,600	)*	(9,900	)	(8,600	)
June 30	(6,300	)*	(7,400	)	(10,300	)
September 30	(5,500	)	(15,800	)	(10,900	)
TOTAL	(29,600	)	(35,100	)	(33,100	)

This election may have immediate short term tax implications as any unit holder who owns units at the time of the election would be deemed to exchange his units for shares in a “new” corporation and to have received a certain amount of deemed dividend income related to having had some share of the Partnership’s public debt “assumed”, as the corporation would assume this liability.

*Assuming ~~Net~~that ~~customers~~the ~~lost~~Partnership’s ~~have~~taxable ~~been~~earnings ~~increased~~and profits are equal to or less than the amount of distributions/dividends paid out during the year by the Partnership and that the unit holder holds the units for the entire calendar year, (or at least long enough during the year to receive a ~~total~~distribution(s) at least equal to the tax resulting from a share of dividend income reported on Form K-1),~~400~~ ~~accounts~~than ~~from~~most ~~previously~~partners ~~disclosed~~should ~~amounts~~not have any material negative cash flow consequences as a result of the Partnership making this election. Note that nothing herein should be interpreted as a projection of any future earnings amount or a projection or guarantee of future distributions or dividends.

WeIn ~~have~~addition, ~~continued~~there toare ~~experience~~risks ~~net~~that ~~customer attrition during fiscal 2007. For~~ the ~~period~~Partnership ~~from October 1 to December 31, 2006, we lost 4,100~~could ~~accounts~~make ~~(net),~~this ~~1.0%~~election ofbut: ~~our home heating oil customer base as compared to the period from October 1 to December 31, 2005 in which we lost 7,200 accounts (net) or 1.6% of our customer base.~~

We• ~~believe~~Not ~~that~~distribute ~~the~~or ~~continued~~dividend ~~price~~enough ~~volatility~~cash ~~and~~to ~~high~~cover ~~cost~~the oftaxes ~~home~~that ~~heating~~may ~~oil~~be ~~will~~due ~~continue~~as toa ~~adversely~~result ~~impact~~of ~~our~~the ~~ability~~dividend toincome ~~attract~~generated ~~customers~~by ~~and retain~~the ~~existing customers~~election.

•

Even if distributions made are equal to the total taxable earnings of the Partnership, a particular unit holder could buy or sell units in a time period that might give rise to deemed dividend income caused by the election and not receive enough (or any) cash to offset the taxes due on such dividend income.

The Partnership intends to only make this election if it believes that it will have no overall material adverse impact on its 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, it 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 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.

Adjusted EBITDA is calculated as earnings from continuing operations before net interest expense, income taxes, depreciation and amortization, the (increase) decrease in the fair value of derivatives, gain or loss on debt redemption, goodwill impairment, and other non-cash and non-operating charges. Management believes the presentation of this measure is relevant and useful because it allows investors to view the Partnership’s performance in a manner similar to the method management uses, and makes it easier to compare its results with other companies that have different financing and capital structures. In addition, this measure is consistent with the manner in which the Partnership’s debt covenants in its material debt agreements are calculated. Both the Partnership’s 10.25% Senior Note agreement and its bank credit facility contain covenants that restrict equity distributions, acquisitions, and the amount of debt it can incur. Under the most restrictive of these covenants, which is found in the bank credit facility, the agent bank could step in and control all cash transactions for the Partnership if we failed to comply with the minimum “Availability” or the fixed charge coverage ratio. The Partnership is required to maintain 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 of 1.1x (Adjusted EBITDA being a significant component of this calculation). This method of calculating Adjusted EBITDA may not be consistent with that of other companies and should be viewed in conjunction with measurements that are computed in accordance with GAAP.

Each of EBITDA and Adjusted EBITDA has its limitations as an analytical tool, and it should not be considered in isolation or as a substitute for analysis of our results as reported under 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.

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 Annual Report. ~~We completed the sale of the propane segment in December 2004. The following discussion reflects the historical results for the propane segment as discontinued operations.~~

20Customer Attrition

We measure net customer attrition for our full service residential and commercial home heating oil customers. Net customer attrition is the difference between gross customer losses and customers added through internal marketing efforts. Customers added through acquisitions are not included in the calculation of gross customer gains. 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.

~~Fiscal~~GROSS ~~Year~~CUSTOMER ~~Ended September 30~~GAINS, ~~2006~~GROSS CUSTOMER LOSSES BY QUARTER AND NET CUSTOMER ATTRITION

Compared to Fiscal Year Ended September 30, 2005


	Fiscal Year Ended
	2009						2008						2007
	Gross Customer				Net Attrition		Gross Customer				Net Attrition		Gross Customer				Net Attrition
	Gains		Losses		Net Attrition		Gains		Losses		Net Attrition		Gains		Losses		Net Attrition
First Quarter	26,300		31,800		(5,500	)	22,000		27,500		(5,500	)	21,500		25,600		(4,100	)
Second Quarter	11,700		24,000		(12,300	)	12,400		19,000		(6,600	)	13,900		19,200		(5,300	)
Third Quarter	5,900		12,300		(6,400	)	8,100		13,700		(5,600	)	6,800		12,900		(6,100	)
Fourth Quarter	10,500		16,500		(6,000	)	18,700		19,300		(600	)	11,300		17,100		(5,800	)

Total	54,400		84,600		(30,200	)	61,200		79,500		(18,300	)	53,500		74,800		(21,300	)


GROSS CUSTOMER GAINS, GROSS CUSTOMER LOSSES AND NET CUSTOMER ATTRITION AS A PERCENTAGE OF THE HOME HEATING OIL CUSTOMER BASE.

	Fiscal Year Ended
	2009						2008						2007
	Gross Customer				Net Attrition		Gross Customer				Net Attrition		Gross Customer				Net Attrition
	Gains		Losses		Net Attrition		Gains		Losses		Net Attrition		Gains		Losses		Net Attrition
First Quarter	6.5	%	7.9	%	-1.4	%	5.3	%	6.6	%	-1.3	%	5.1	%	6.1	%	-1.0	%
Second Quarter	2.9	%	6.0	%	-3.1	%	3.0	%	4.6	%	-1.6	%	3.3	%	4.5	%	-1.2	%
Third Quarter	1.5	%	3.1	%	-1.6	%	2.0	%	3.3	%	-1.3	%	1.6	%	3.1	%	-1.5	%
Fourth Quarter	2.6	%	4.1	%	-1.5	%	4.5	%	4.6	%	-0.1	%	2.7	%	4.0	%	-1.3	%

Total	13.5	%	21.0	%	-7.5	%	14.7	%	19.1	%	-4.4	%	12.6	%	17.6	%	-5.0	%

In fiscal 2009, we lost 30,200 accounts, net, or 7.5% of our home heating oil customer base, as compared to fiscal 2008 in which we lost 18,300 accounts, net, or 4.4 % of our home heating oil customer base. The increase in net losses of 11,900 accounts occurred primarily in the second and fourth quarters of fiscal 2009. In the second quarter of fiscal 2009, our gross customer losses were 24,000, or 5,000 accounts greater than the second quarter of fiscal 2008. This increase in gross losses was largely from our fixed price customers, and to a lesser extent, our ceiling customers. As a result of significant decreases in the price of home heating oil following the summer of 2008, many protected price customers decided to renegotiate their agreements with us in fiscal 2009. It is our policy to bill a termination fee when customers terminate their arrangement with us. It is our belief that approximately 10,000 customers chose another supplier as a result of being billed the termination fee. This compares to approximately 4,300 customers who terminated their relationship in fiscal 2008 after we billed a termination fee.

In the fourth quarter of fiscal 2009, we gained 10,500 customers or 8,200 fewer customers than in the fourth quarter of fiscal 2008. We believe that this substantial drop in customer gains was due to a lower level of interest in our product in the fourth quarter of fiscal 2009, as compared to the same period in fiscal 2008, as consumer concerns over record increases in home heating oil costs in the summer of 2008 drove many consumers to shop for a protected price in the summer of 2008. In addition, certain of our locations experienced a substantial increase in customer gains in the fourth quarter of fiscal 2008 due to the volatile home heating oil market conditions. Some of our competitors ceased to offer protected price plans during the fourth quarter of 2008 due to an increase in the cost to hedge these programs, which also positively impacted our customer gains in fiscal 2008.

In fiscal 2009, our gross customers gains decreased by 6,800 accounts to 54,400 accounts (13.5 % of our home heating oil customer base) when compared to gross customer gains of 61,200 (14.7 % of our home heating oil customer base) generated in fiscal 2008. As mentioned above, the decline in gross customer gains that occurred in fiscal 2009 was largely experienced in the fourth quarter of fiscal 2009. In addition, we believe that gains from real estate sources in fiscal 2009 declined by 2,500 accounts primarily as a result of the reduction in house sales during this period.

In fiscal 2009, our gross customer losses increased by 5,100 accounts to 84,600 (21.0 % of our home heating oil customer base) when compared to 79,500 in gross customer losses for fiscal 2008 (19.1 % of our home heating oil customer base). As noted above, gross losses from customers that were billed a termination fee increased by 5,700 accounts and the number of accounts that the Partnership proactively cancelled for credit increased by 2,400 accounts.

In fiscal 2008, we lost 18,300 accounts, net, or 4.4% of our home heating oil customer base, as compared to fiscal 2007 in which we lost 21,300 accounts, net, or 5.0% of our home heating oil customer base. For fiscal 2008, our gross customers gains increased by 7,700 accounts to 61,200 accounts (14.7 % of our home heating oil customer base) when compared to the gross customer gains of 53,500 (12.6 % of our home heating oil customer base) generated in fiscal 2007. The increase in

gross customer gains in fiscal 2008 was largely due to the success of our customer and employee referral programs, selective media advertising and the unique circumstances, previously mentioned, that existed in the fourth quarter of fiscal 2008. Our gross customer losses increased by 4,700 in fiscal 2008 to 79,500 (19.1% of our home heating oil customer base) when compared to the 74,800 in gross customer losses for fiscal 2007 (17.6% of our home heating oil customer base). In fiscal 2008, we experienced an increase in losses to price (6,300), credit (2,500) and conversions to natural gas (2,400), and our losses from customers moving out of their existing home declined by 5,700.

We believe that the continued price volatility and high cost of home heating oil will adversely impact our ability to attract customers and retain existing customers in the future.

Fiscal Year Ended September 30, 2009

Compared to the Fiscal Year Ended September 30, 2008

Volume

For fiscal ~~2006~~2009, retail volume of home heating oil ~~declined~~decreased by 97 1.47 million gallons, or ~~20.~~0.5%, to ~~389~~349.94 million gallons, as compared to ~~487~~ 351.31 million gallons for fiscal ~~2005~~2008. Volume of other petroleum products declined by 119.53 million gallons, or 1519.80%, to 6239.06 million gallons for fiscal ~~2006~~ 2009, as compared to 7348.59 million gallons for fiscal ~~2005~~2008. An analysis of the change in the retail volume of home heating oil, which is based on management’s estimates, sampling and other mathematical calculations, is found below:

(in millions of gallons)	Heating Oil Segment
(In millions of gallons)	Heating Oil
Volume—Fiscal 2005	487.3
Volume—Fiscal 2008	351.1
Impact of warmer temperatures	(53.6	)
Impact of colder temperatures	28.4
Net customer attrition	(36.0	)
Net customer attrition—retail and commercial	(28.7	)
Asset sale	(2.3	)
Acquisitions	6.1
Conservation and other, net	(5.5	)
Conservation/Other	(7.5	)
Change	(971.47	)
Volume—Fiscal 2006	389.9
Volume—Fiscal 2009	349.4

Temperatures in our geographic areas of operations for fiscal ~~2006~~2009 were 118.01% ~~warmer~~ colder than fiscal ~~2005~~ 2008 and ~~approximately 10~~1.43% ~~warmer~~colder than normal, as reported by the National Oceanic ~~Atmospheric~~ Administration (“NOAA”). For fiscal 2009, net customer attrition was 7.5%. Due to the significant increase in the price per gallon of home heating oil over the last several years, we believe that customers are using less home heating oil given similar temperatures when compared to prior periods. Weand ~~cannot~~this ~~determine~~decrease ~~if conservation~~ is areflected ~~permanent or temporary phenomenon. Home heating oil volume declined by 2.3 million gallons due to the sale of certain of our assets~~ in ~~New England. Excluding~~ the ~~impact~~“Conservation/Other” ofheading ~~weather, we expect that home heating oil volume for the fiscal quarter ended December 31, 2006 and fiscal 2007 will be substantially less than the comparable period~~ in fiscal 2006 due to net customer attrition, conservation and other factors. In addition, we expect that home heating oil volume for fiscal 2007 will be adversely affected by warmer than normal temperatures. Temperatures from October 1, 2006 to January 14, 2007 in the ~~New~~ ~~York~~above ~~City area, which approximates our geographic areas of operations, were 20~~table.6% ~~warmer than normal. From October 1, 2005 to January 31, 2006, temperatures in our areas of operations were 8.5% warmer than normal.~~

The percentage of home heating oil volume sold to residential variable price customers decreased to 40.1% of total home heating oil volume sales for fiscal 2009, as compared to 42.9% for fiscal 2008. Accordingly, the percentage of home heating oil volume sold to residential price-protected customers increased to 45.5% for fiscal 2009, as compared to 42.4% for fiscal 2008. For fiscal 2009, sales to commercial/industrial customers represented 14.3% of total home heating oil volume sales, as compared to 14.7% for fiscal 2008.

Product Sales

For fiscal ~~2006~~2009, product sales ~~increased~~ decreased $38321.1 million, or 323.67%, to $1~~,109~~.3033 ~~million~~billion, as compared to $1~~,071~~.3354 ~~million~~billion for fiscal ~~2005~~2008, due to ~~an increase in selling prices, which more than offset~~ a ~~decline~~20.0% decrease in home heating oil ~~volume~~selling ~~sold. Selling~~ prices, ~~were~~a ~~higher~~0.5% indecrease ~~response to the increase~~ in ~~wholesale~~ home heating oil ~~supply~~volume, ~~costs noted below of $0.4307 per gallon~~ and ~~our~~a ~~decision~~decline toin ~~pursue~~sales ~~higher~~of ~~per~~other ~~gallon~~petroleum ~~gross~~products ~~profit~~of ~~margins, particularly from our price-protected customers. Average home heating oil prices increased from~~ $176.~~9405~~9 ~~per gallon for fiscal 2005 to $2~~million.~~5067~~ ~~for fiscal 2006.~~

In an effort to reduce net customer attrition, we delayed increasing our selling price to certain customers whose price plan agreements expired during the July to September 2004 time period. This decision negatively impacted sales by an estimated $2.8 million in fiscal 2005, primarily during the first quarter of fiscal 2005.

Installation and Service Sales

For fiscal ~~2006~~2009, ~~service~~installation and ~~installation~~service sales decreased $115.01 million, or 08.50%, to $~~187~~174.20 million, as compared to $~~188~~189.21 million for fiscal ~~2005.~~2008, ~~Installation~~as a decline in installation sales ~~decreased~~of $15.2 million was reduced by a slight increase in service revenue of $20.1 million;. ~~however~~We believe that rising unemployment, ~~despite~~reduced home equity loans and consumer credit, and reduced consumer confidence led to a decline in the ~~customer~~demand for new heating systems ($8.3 million), air conditioning equipment ~~base~~($2.2 million), ~~service~~as ~~revenues~~well ~~increased~~as new construction plumbing installations ($14.15 million). ~~due~~The tocool ~~measures~~spring ~~taken~~also inadversely impacted the ~~last~~demand ~~several~~for ~~years~~new toand ~~increase~~replacement air conditioning systems over the summer months. While service ~~billing~~contract revenue increased by $2.2 million, revenue from non-essential services, which include plumbing and air conditioning service, ~~contract~~declined ~~rates~~$2.1 million. We believe that the decline in non-essential service revenue is the result of current economic conditions.

Cost of Product

For fiscal ~~2006~~2009, cost of product ~~increased~~decreased $39373.48 million, or 534.05%, to $~~825~~708.72 million, as compared to $~~786~~1.3082 ~~million~~billion for fiscal ~~2005~~2008, asdue ~~higher~~largely ~~wholesale~~to ~~product~~a ~~cost~~decline ~~was~~in ~~reduced~~the bywholesale ~~lower~~product cost for home heating oil ~~volume~~and ~~of 20.0%.~~other ~~Average~~petroleum ~~wholesale~~products. ~~product~~The ~~cost~~0.5% decline ~~for~~in home heating oil ~~increased~~volume bysold ~~$0.4307~~and ~~per~~the ~~gallon, or 30~~19.0%, todecline anin ~~average~~other ofpetroleum ~~$1.8137~~products ~~per~~sold ~~gallon~~also ~~for~~contributed ~~fiscal~~to ~~2006,~~the ~~from~~decline anin ~~average~~cost of $1product.~~3831~~ ~~for fiscal 2005.~~

We28 believe that 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. Home heating oil margins for fiscal 2006 increased by $0.1355 per gallon to $ 0.6930 per gallon in fiscal 2006 from $ 0.5575 per gallon in fiscal 2005 due largely to an increase in the margin realized on price-protected customers, an increase in the percentage of volume sold to higher margin residential variable customers, an increase in home heating oil margins realized on new accounts, the loss of some of our less profitable accounts and our decision in the summer of fiscal 2005 and fiscal 2006 to maintain profit margins going forward in spite of competitors’ aggressive pricing tactics. During the renewal period for price-protected customers in fiscal 2004, which was a period of rising heating oil prices, a number of residential variable consumers migrated to price protected plans. This shift resulted in an increase in volume sold to residential price-protected customers for the heating season of fiscal 2005. During the renewal period for price-protected customers in fiscal 2005, a period with even higher average heating oil prices than the renewal period in fiscal 2004, a number of residential price-protected customers elected variable pricing or failed to respond to our price-protected programs, which resulted in a shift back to variable pricing for these customers. The percentage of home heating oil volume sold to residential variable price customers increased to 45.0% of total home heating oil volume sales for fiscal 2006, as compared to 36.0% for fiscal 2005. Accordingly, the percentage of home heating oil volume sold to residential price-protected customers decreased to 38.3% for fiscal 2006, as compared to 48.0% for fiscal 2005. For fiscal 2006, sales to commercial/industrial customers represented 16.7% of total home heating oil volume sales, as compared to 16.0% for fiscal 2005.

AlsoTable contributing to the increase in home heating oil per gallon margins were the favorable market conditions experienced during the first quarter of fiscal 2006, as compared to the first quarter of fiscal 2005. During the three months ended December 31, 2004, home heating oil prices spiked by over 20 cents a gallon from the beginning of the period and contributed to margin compression experienced during the three months ended December 31, 2004. Conversely, during the three months ended December 31, 2005, home heating oil prices declined by over 30 cents per gallon from the beginning of the period, which contributed to the expansion of home heating oil margins during this period, as we were able to lag the reduction in our variable selling prices as the wholesale cost of heating oil declined. Contents

InGross ~~addition,~~Profit—Product the year-over-year comparison was favorably impacted by $3.4 million of expenses that we incurred in fiscal 2005 due to a delay in hedging the price of product for certain residential price-protected customers, as well as an additional $1.6 million of expenses associated with not hedging until December 2004 the price of product for certain residential price-protected customers that were incorrectly coded as variable customers.

~~For~~The ~~fiscal~~table ~~2006,~~below ~~total~~recalculates the Partnership’s per gallon margins and reconciles product gross profit ~~decreased~~for byhome ~~$1.3~~heating ~~million,~~oil asand ~~compared~~other petroleum toproducts. ~~fiscal 2005,~~We asbelieve the ~~increase~~change in ~~realized~~ 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 ~~$52.8~~non-cash ~~million~~changes ~~was~~in ~~more~~the ~~than~~market ~~offset~~value byof hedges before the ~~decline~~settlement of the underlying transaction. On that basis, home heating oil margins for fiscal 2009 increased by $540.31522 ~~million~~per ~~attributable~~gallon, or 20.5%, to ~~the~~$0.8935 ~~decline~~per gallon, from $0.7413 per gallon in fiscal 2008. Product sales and cost of product include home heating oil, ~~volume~~other petroleum products and liquidated damages billings.

Change in the Fair Value of Derivative Instruments


	Fiscal Year Ended
	September 30, 2009				September 30, 2008
	Amount (000)		Per Gallon		Amount (000)		Per Gallon
Home Heating Oil
Volume (in millions of gallons)		349.4				351.1

Sales	$	954.5	$	2.7318	$	1,198.6	$	3.4137
Cost		642.3		1.8383		938.3		2.6724

Gross Profit	$	312.2	$	0.8935	$	260.3	$	0.7413


	Amount (000)		Per Gallon		Amount (000)		Per Gallon
Other Petroleum Products
Volume (in millions of gallons)		39.6				48.9

Sales	$	78.4	$	1.9785	$	155.3	$	3.1761
Cost		65.9		1.6640		143.5		2.9343

Gross Profit	$	12.5	$	0.3145	$	11.8	$	0.2418


	Amount (000)				Amount (000)		Change
Total Product
Sales	$	1,032.8			$	1,353.9	$	(321.1	)
Cost		708.2				1,081.8		(373.6	)

Gross Profit	$	324.6			$	272.1	$	52.5

~~Home~~For ~~heating oil prices increased in the fourth quarter of~~ fiscal ~~2005~~2009, intotal ~~response~~product togross ~~the~~profit ~~numerous~~increased ~~hurricanes~~by in$52.5 ~~the~~million ~~Gulf Coast and we recorded a significant mark~~ to ~~market gain~~$324. ~~In September 2006~~6 million, ~~the~~as ~~home~~compared ~~heating prices collapsed and we recorded a mark~~ to ~~market loss. As a result of these events, the impact on the change in the fair value of derivative instruments is~~ $45272.71 million for fiscal ~~2006.~~2008, Inas the ~~summers~~impact of ~~fiscal~~higher ~~2005 and fiscal 2004,~~ home heating oil ~~prices~~per ~~increased which~~gallon ~~resulted~~margins in($53.2 ~~the~~million) ~~recording~~and ofan ~~unrealized~~increase ~~gains~~in atgross ~~the~~profit ~~close~~from ofother ~~both~~petroleum ~~fiscal~~products ~~2005 and fiscal 2004~~($0.6 ~~The~~million) ~~net~~was ~~gain~~reduced ~~for~~by ~~fiscal 2005 exceeded~~ the ~~gain~~impact ~~for~~of ~~fiscal~~lower ~~2004~~home heating byoil volume ($6.1.3 million.)

During the heating season of fiscal 2009, home heating oil product costs continued to decline, which largely contributed to the Partnership’s ability to expand its home heating oil margins during this period, as wholesale prices decreased more rapidly than retail prices. Conversely, during the heating season of fiscal 2008, home heating oil costs continued to escalate, which limited margin expansion capability.

Cost of Installations and Service

For fiscal ~~2006~~2009, cost of installations, ~~service~~ and ~~appliances~~ service decreased $8.2 million, or 4.27%, to $~~189~~167.26 million, as compared to $~~197~~175.48 million for fiscal ~~2005.~~2008, ~~The~~as ~~4.2%~~a decrease in ~~cost~~installation costs of ~~installation~~$11.6 ~~and~~million ~~service~~ was ~~less~~partially ~~than~~offset ~~the~~by 6higher service expenses of $3.6%4 ~~decrease~~million. inInstallation ~~customers~~costs ~~for~~were ~~fiscal~~lower, ~~2006~~largely due to the ~~fixed~~corresponding ~~nature~~decrease ofin ~~these~~installation sales as described above. Service expenses. ~~The~~were ~~net~~higher ~~loss~~due ~~realized~~to ~~from~~an ~~service~~increase ~~(including~~in ~~installations)~~vehicle ~~improved~~fuel bycosts of $7.2.1 million, ~~from~~as the Partnership hedged a ~~$9.2~~portion ~~million~~of ~~loss~~its ~~for~~vehicle ~~fiscal~~fuel ~~2005~~costs toduring a higher cost period. For fiscal 2010, the Partnership has again hedged its vehicle fuel costs, which should lower this expense by approximately $2.03 million ~~loss~~in ~~for~~ fiscal ~~2006~~2010. Colder than normal winter

~~Delivery~~29 ~~and Branch Expenses~~

For fiscal 2006, delivery and branch expenses decreased $26.5 million, or 11.5%, to $205.0 million, as compared to $231.6 million for fiscal 2005. This decrease was due to a reduction in marketing expenses of $6.0 million, an estimated

~~$15.2~~ temperatures ~~million~~also ~~decrease~~increased inthe ~~certain~~operating ~~variable~~expense ~~operating~~of ~~expenses~~the ~~directly~~service ~~associated~~department ~~with~~due to the ~~20.0%~~increased ~~decline~~need into ~~home~~service our customer’s heating equipment. The gross profit realized from service ~~oil~~(including ~~volume~~installations) decreased by $7.0 million, from $13.4 million for fiscal 2008 to $6.4 million ~~received~~for ~~under~~fiscal ~~our~~2009 ~~weather~~due ~~insurance~~to ~~policy,~~the ~~lower~~decline ~~bad~~in ~~debt~~installation ~~expense~~sales and ~~collection~~the increase in vehicle fuel costs. Installation costs were $53.0 million, or 88.6% of installation sales during fiscal 2009, and were $464.75 million, ~~due~~or in86.0% ~~part~~of toinstallation ~~more~~sales ~~stringent~~during ~~credit~~fiscal ~~terms~~2008. ~~and~~Installation ~~other~~costs ~~expense~~as ~~reductions~~a percentage of installation sales increased due to the fixed nature of certain installation costs. Service expenses increased to $0114.7 million, ~~offset~~or by100.4% ~~wage~~of ~~and~~service ~~benefit increases~~sales, ofduring ~~approximately~~fiscal 2009, from $4111.43 million in fiscal 2008, or 97.5% Onof service sales. Service costs as a ~~cents~~percentage ~~per~~of ~~gallon~~total ~~basis~~service ~~(excluding~~revenue increased due to the ~~proceeds~~rise ~~received~~in ~~from~~vehicle ~~weather~~fuel costs ~~insurance)~~and, ~~delivery~~the ~~and~~impact ~~branch~~on ~~expenses~~service ~~increased~~costs ~~6.2~~of ~~cents~~colder ~~per~~temperatures. ~~gallon~~In addition, orthe ~~13%,~~Partnership ~~from~~was ~~47.5~~not ~~cents~~able ~~per~~to ~~gallon~~fully ~~for~~reduce ~~fiscal~~its ~~2005~~service expenses in response to ~~53.7 cents~~unforeseen ~~per~~reductions ~~gallon~~in ~~for~~non-essential ~~fiscal~~service ~~2006~~billings ~~due~~such as air conditioning and plumbing services, which also contributed to the ~~fixed~~increase ~~nature~~in the percentage of ~~certain~~service ~~delivery~~expense ~~and~~to ~~branch~~service revenues. For fiscal 2010, the Partnership expects that service revenues will exceed service expenses.

(Increase) Decrease in the Fair Value of Derivative Instruments

During fiscal 2009, the change in the fair value of derivative instruments resulted in the recording of a $13.7 million credit due to the expiration of certain hedged positions ($21.2 million credit), and a decrease in market value for unexpired hedges ($7.5 million charge).

During fiscal 2008, the change in the fair value of derivative instruments resulted in the recording of a $25.5 million charge due to the expiration of certain hedged positions ($1.3 million charge), and a decrease in market value for unexpired hedges ($24.2 million charge).

Delivery and Branch Expenses

For fiscal 2009, delivery and branch expenses increased $10.8 million, or 5.1%, to $222.7 million, as compared to $211.9 million fiscal 2008. While our bad debt expense did decline by $1.6 million due in part to the decline in sales of 21.8 %, we increased our collections efforts which resulted in an increase in overall credit collection expense by $1.0 million. Delivery and plant expense, rose by $4.8 million due in part to the impact of colder temperatures and higher vehicle fuel costs of $2.2 million, as the Partnership hedged a portion of its vehicle fuels during a higher cost period. The balance of the increase in delivery and plant expense was $2.6 million, or 3.7%, largely driven by wage and benefit increases. In an effort to improve our customer experience and improve our net attrition, we spent an additional $2.2 million on marketing, sales and customer service in fiscal 2009 as compared to fiscal 2008. Insurance expense was also higher by $1.0 million largely due to both the frequency and size of our claims in fiscal 2009 versus fiscal 2008. Other branch expenses increased $3.4 million due to higher wages, benefits and rent. On a cents per gallon basis, delivery and branch expenses increased 3.41 cents per gallon, or 5.6%, from $0.6034 cents per gallon for fiscal 2008, to $0.6375 cents per gallon for fiscal 2009, due to the fixed nature of certain delivery and branch expenses, the increases in insurance expense and vehicle fuel cost and inflationary pressures.

Depreciation and Amortization

For fiscal ~~2006~~2009, depreciation and amortization expenses ~~declined~~were by $319.14 million, oras ~~8.7%,~~compared to $3226.48 million, asfor ~~compared~~fiscal to2008. Amortization expense was lower by $356.53 million, ~~for~~as acquisitions from fiscal ~~2005~~ 2001 with 7 year lives and acquisitions from 1999 with 10 year lives became fully amortized in fiscal 2009. Depreciation expenses declined by $1.1 million as ~~certain~~capital ~~assets,~~expenditures ~~which~~for technology ~~were~~acquired ~~not~~in ~~replaced,~~fiscal 2003 became fully depreciated.

General and Administrative Expenses

For fiscal ~~2006~~2009, general and administrative expenses ~~decreased~~increased by $214.54 million, or 4924.84%, to $2122.7 5 million, as compared to $4318.21 million for fiscal ~~2005~~ 2008, largely due to ~~the~~higher ~~absence~~compensation ofexpense ~~bridge financing expenses~~ of $72.51 million, ~~which~~relating ~~were~~to ~~incurred~~the inPartnership’s ~~fiscal~~profit ~~2005,~~sharing ~~lower~~plan ~~fees~~ and ~~expenses~~an ~~totaling~~increase ~~$3.4~~in ~~million~~pension ~~associated~~expense ~~with~~of ~~certain~~$1.6 ~~amendments~~million ~~and~~largely ~~waivers~~due onto ~~our~~the ~~previous~~decline ~~bank~~in ~~credit facility obtained during~~ the ~~first~~assets ~~fiscal quarter~~ of ~~2005,~~the ~~lower~~Partnership’s frozen ~~compensation~~defined ~~expense~~benefit ofpension $0plan.9 ~~million~~The ~~attributable~~balance toof ~~staff~~the ~~reductions~~increase, aor $50.67 million, ~~decline~~was indue ~~legal expenses related~~ to ~~defending~~wage ~~several~~increases ~~purported~~and ~~class~~higher ~~action~~legal ~~lawsuits~~ and ~~exploring~~professional ~~financing options in fiscal 2005, $3~~expenses.3 ~~million~~The ~~less~~Partnership inaccrues ~~first~~approximately ~~year~~6% ~~Sarbanes-Oxley~~of ~~compliance~~Adjusted ~~cost,~~EBITDA aas ~~$3.8~~defined ~~million~~in ~~reduction~~the inprofit ~~compensation~~sharing plan ~~expense~~for ~~related~~distribution to ~~separation~~its ~~agreements~~employees ~~recorded~~and inis ~~the~~payable ~~prior~~when ~~period~~the ~~with~~Partnership ~~certain~~achieves ~~former~~actual ~~executives,~~adjusted ~~other~~EBITDA ~~expense reductions~~ of ~~$0.6~~ ~~million,~~at ~~and~~least a70% ~~gain~~of on the ~~sale~~amount ~~of certain assets of $0~~budgeted.9 ~~million.~~In ~~Partially~~fiscal ~~offsetting~~2009, ~~these~~adjusted ~~reductions~~EBITDA ~~was~~increased anby ~~increase in directors and officers liability insurance expense of~~ $030.7 3 million ~~and~~to $185.4 8 million, ofwhich ~~legal~~drove ~~and professional expenses~~the ~~incurred~~increase in ~~fiscal~~profit ~~2006~~sharing ~~relating~~expense. toIf ~~the~~Adjusted ~~exploration~~EBITDA ofincreases, ~~our~~the ~~financial~~dollar ~~options.~~amount Inof ~~addition,~~ the ~~fiscal~~profit ~~2005~~sharing ~~results~~pool ~~were~~will ~~positively~~increase. ~~impacted~~On bythe aother ~~reversal~~hand, ofif ~~previously~~Adjusted ~~recorded~~EBITDA ~~compensation~~decreases, ~~expenses~~the ofdollar ~~$2.2~~amount ~~million~~of ~~due to~~ the ~~decline~~profit insharing ~~the~~pool ~~price~~will ~~of senior~~be ~~subordinated units~~less.

~~Goodwill~~30 ~~Impairment Charge~~

During the fiscal second quarter of 2005, a number of events occurred that indicated a possible impairment of goodwill might exist. These events included our determination in February 2005 of significantly lower than expected operating results for the year and a significant decline in the Partnership’s unit price. As a result of these triggering events and circumstances, the Partnership completed an additional SFAS 142 impairment review with the assistance of a third party valuation firm at February 28, 2005. This review resulted in a non-cash goodwill impairment charge of approximately $67.0 million, which reduced the carrying amount of goodwill. There was no goodwill impairment charge recorded during fiscal 2006.

Operating Income (Loss)

For fiscal 2006 operating income increased $72.2 million to a $23.2 million loss, as compared to an operating loss of $95.4 million fiscal 2005. This increase was due to the non-recurrence during fiscal 2006 of a $67.0 million goodwill impairment charge recorded in fiscal 2005, a $52.8 million increase in heating oil gross profit due to higher home heating oil margins, a $48.1 million decline in branch and general and administrative expenses, reduction in the net service and installation loss of $7.2 million, lower depreciation and amortization expense of $3.1 million, reduced by a decrease in heating oil gross profit of $54.3 million due to lower volume and the impact of comparative change in the fair value of derivative instruments of $51.8 million.

Loss on Redemption of Debt

For fiscal 2006, we recorded a $6.6 million loss on the early redemption and conversion of our 10.25% senior notes (See Notes 3 and 15 of the Consolidated Financial Statements). The loss consists of the $5.4 million attributable to the difference between the value of the Partnership’s common units ($32.2 million) exchanged for debt ($26.9 million), and the write-off of previously capitalized net deferred financing costs of $2.0 million, reduced in part by a $0.8 million basis adjustment to the carrying value of long-term debt.

For fiscal 2005, we recorded a $42.1 million loss on the early redemption of certain notes in connection with the sale of the propane segment. The loss consisted of cash premiums paid of $37 million for early redemption, the write-off of previously capitalized net deferred financing costs of $6.1 million and legal expenses of $0.7 million, reduced in part by a $1.7 million basis adjustment to the carrying value of long-term debt.

~~Interest~~Operating ~~expense~~Income

For fiscal ~~2006~~2009, ~~interest~~operating ~~expense~~income ~~decreased~~increased $976.98 million, ~~or 27.3%,~~ to $2680.31 million, as compared to $363.23 million for fiscal ~~2005.~~2008 ~~This~~as ~~decrease~~a ~~resulted~~net ~~from~~positive achange ~~lower~~in ~~principal~~the ~~amount~~fair invalue ~~total~~of ~~debt~~derivative ~~outstanding~~instruments of ~~approximately~~ $~~142~~39.5 2 million, ~~which~~and ~~was~~an ~~offset~~increase in ~~part~~product bygross anprofit ~~increase~~of in$52.5 ~~the~~million ~~Partnership’s~~was ~~weighted~~reduced ~~average~~by ~~interest~~lower ~~rate~~installation ofand ~~1.2%~~service ~~from~~profitability 8totaling $7.9%0 ~~during~~million ~~fiscal~~and ~~2005~~an toincrease ~~10.1%~~in ~~for~~operating ~~fiscal~~expenses ~~2006~~of $7.9 million (including depreciation and amortization).

~~Total~~Interest ~~debt~~Expense outstanding declined by $142.5 million due to the recapitalization (see Notes 3 and 15 to the Consolidated Financial Statements) and lower working capital borrowings as a portion of the proceeds from the sale of the propane segment was used to fund working capital.

For fiscal 2009, interest expense decreased $2.9 million, or 13.8%, to $17.8 million, as compared to $20.7 million in fiscal 2008. In fiscal 2009, the Partnership repurchased $40.3 million of its 10.25% Senior Notes due February 2013, which lowered the average long-term debt outstanding by $26.7 million and corresponding interest expense by $2.7 million. Working capital interest expense, including letters of credit fees, increased by $0.5 million.

Interest Income

For fiscal ~~2006~~ 2009, interest income ~~increased~~decreased by $02.87 million, ~~or 17.9%,~~ to $54.12 million, as compared to $46.39 million for fiscal ~~2005~~2008, due to a reduction in interest income of $1.1 million from invested cash and a decrease in finance charge income on past due accounts receivable balances. While average cash balances were higher in fiscal 2009 than in fiscal 2008, the investment returns were lower. Finance charge income declined largely due to a lower level of aged accounts receivables.

Amortization of Debt Issuance Costs

For fiscal ~~2006~~2009, amortization of debt issuance costs ~~was~~increased to $2.48 million, as compared to fiscal 2008 of $02.13 million ~~less~~largely ~~than~~due ~~fiscal~~to ~~2005~~the accelerated amortization of fees related to the revolving credit facility that was amended in July 2009.

~~Income~~Gains ~~Tax~~on ~~Expense~~Bond Repurchase

~~Income~~During ~~tax~~fiscal ~~expense~~2009, ~~for~~the ~~fiscal~~Partnership ~~2006~~repurchased ~~was~~ $040.53 million ~~and~~face ~~represents~~value ~~certain~~of ~~state~~its ~~income~~10.25% ~~tax,~~Senior ~~alternative~~Notes ~~minimum~~due ~~federal~~February ~~tax~~2013 ~~and~~at ~~capital~~an ~~tax.~~average ~~Income tax~~price ~~expense~~of ~~for fiscal 2005 was~~ $075.710 ~~million.~~per ~~The~~$100 ~~decrease~~of inprincipal ~~state~~plus ~~taxes~~accrued ~~for~~interest. ~~2006~~The Partnership asrecorded ~~compared~~a togain ~~2005~~of ~~was~~$9.7 ~~largely~~million ~~attributable~~for tothese ~~an election made at the state level during the fourth quarter of 2006~~transactions.

~~Loss~~Income ~~From~~Tax ~~Continuing~~Expense ~~Operations~~(Benefit)

For fiscal ~~2006~~2009, an income tax benefit of $86.4 million was recorded for the release of a majority of our opening valuation allowance. This ~~loss~~benefit ~~from~~was ~~continuing~~offset ~~operations~~by ~~decreased~~a current income tax expense of $~~118~~3.78 million and a deferred income tax expense of $25.0 million related to current year activity, resulting in a net income tax benefit of $5357.9 6 million, as compared to aincome ~~loss~~tax expense of $~~172~~0.6 million for fiscal ~~2005~~2008. ~~This~~Based ~~change~~upon ~~was~~a ~~due~~review toof ~~the~~a ~~$72.2~~number ~~million~~of ~~increase~~factors, inincluding historical operating performance and our expectation that we could generate sustainable consolidated taxable income for the foreseeable future, awe concluded ~~$9.9~~at ~~million~~the ~~decline~~end inof ~~interest~~fiscal ~~expense~~2009 ~~and a~~that ~~$0.8~~the ~~million~~majority ~~increase~~of inthe ~~interest~~Partnership’s ~~income~~net deferred tax assets should be recognized. ~~The~~Thus, ~~year~~pursuant ~~over~~to ~~year~~FASB ~~comparison~~ASC ~~was~~740-10-05 ~~favorably~~Income ~~impacted~~Taxes bytopic a(SFAS ~~$35~~No.5 109), ~~million~~we ~~reduction~~recorded ina tax benefit during fiscal 2009 releasing a majority of the ~~loss~~remaining onvaluation ~~redemption~~allowance, resulting in a non-cash increase in net income of ~~debt~~$86.4 million.

~~Loss~~For ~~From~~the ~~Discontinued~~next ~~Operations~~several years, our income tax expense will consist of two components, a current income tax expense and a deferred income tax expense. The current tax expense will represent our expected cash taxes. The deferred tax expense will represent the amount of income taxe that we would have paid if we do not have the benefit of our net loss carry forwards and other deferred tax assets.

~~The~~Net ~~discontinued~~Income ~~propane~~(Loss) ~~segment was sold on December 17, 2004 and it generated a $6.2 million loss in fiscal 2005.~~

~~Gains~~For Onfiscal ~~Sale~~2009, net income of ~~Segments~~$131.0 million was recorded, as compared to a net loss of $13.4 million for fiscal 2008. This increase of $144.4 million was primarily due to a $76.8 million increase in operating income, gains on bond repurchases of $9.7 million and lower income tax expense of $58.2 million.

~~During~~31 fiscal 2005, the Partnership recorded a gain on the sale of the propane segment of $156.8 million. Additionally, the purchase price for the TG&E segment was finalized and a positive adjustment of $0.8 million was recorded in fiscal 2005. There were no similar transactions in fiscal 2006

Cumulative Effect of Change in Accounting Principle

Effective October 1, 2005, we changed our method of accounting from the first-in, first-out method to the weighted average cost method for heating oil and other fuels. This change resulted in the recording of a charge of $0.3 million.

Net Loss

For fiscal 2006, net loss increased by $33.1 million to $54.3 million as a $118.7 million increase in income from continuing operations and a $6.2 million decline in the loss from discontinued operations in the 2005 fiscal first quarter was offset by the gains on the sale of discontinued operations recorded in the year ago period of $157.6 million and the $0.3 million charge for the change in accounting principle.

Earnings From Continuing Operations Before Interest, Taxes, Depreciation and Amortization (EBITDA)

For fiscal 2006, EBITDA increased $104.6 million, to $2.6 million, as compared to an EBITDA loss of $102.0 million for fiscal 2005. For fiscal 2006, EBITDA was reduced by $ 6.6 million due to the non-cash loss for the early redemption of debt and the non-cash change in the fair value of derivative instruments of $45.7 million in fiscal 2006. For fiscal 2005, EBITDA was reduced by $ 67.0 due to a goodwill impairment charge and $ 42.1 million due to the non-cash loss for the early redemption of debt. In fiscal, 2005, EBITDA was favorably impacted by $6.1 million due to the change in the fair value of derivative instruments.

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

	Fiscal Year Ended September 30,
(in thousands)	2006			2005
				(restated)
Loss from continuing operations	$	(53,919	)	$	(172,580	)
Plus:
Income tax expense		477			696
Amortization of debt issuance costs		2,438			2,540
Interest expense, net		21,203			31,838
Depreciation and amortization		32,415			35,480
EBITDA		2,614			(102,026	)
Add/(subtract)
Income tax expense		(477	)		(696	)
Interest expense, net		(21,203	)		(31,838	)
Unit compensation expense (income)		—			(2,185	)
Provision for losses on accounts receivable		6,105			9,817
Gain on sales of fixed assets, net		(956	)		(43	)
Goodwill impairment loss		—			67,000
Loss on redemption of debt		6,603			42,082
Unrealized (gains) losses on derivative contracts		45,677			(6,081	)
Change in operating other assets and liabilities		(19,999	)		(30,945	)
Net cash provided by (used in) operating activities	$	18,364		$	(54,915	)

For fiscal 2009, Adjusted EBITDA increased by $30.3 million to $85.8 million, as compared to $55.5 million for fiscal 2008, as an expansion in home heating oil margins more than offset the impact of a decline in home heating oil volume and an increase in delivery and branch expense and general and administrative expenses.

2532

~~Fiscal~~Adjusted ~~Year~~EBITDA ~~Ended September 30, 2005~~

~~Compared~~EBITDA and Adjusted EBITDA should not be considered as an alternative to ~~Fiscal~~net ~~Year~~income ~~Ended~~(as ~~September 30~~an indicator of operating performance) or as an alternative to cash flow (as a measure of liquidity or ability to service debt obligations), ~~2004~~but provides additional information for evaluating our ability to make the Minimum Quarterly Distribution. EBITDA and Adjusted EBITDA are calculated as follows:


	Fiscal Year Ended September 30,
(in thousands)	2009			2008
Income (loss) from continuing operations	$	131,038		$	(13,408	)
Plus:
Income tax expense (benefit)		(57,597	)		566
Amortization of debt issuance cost		2,750			2,339
Interest expense, net		13,637			13,808
Depreciation and amortization		19,406			26,784

EBITDA (a) from continuing operations		109,234			30,089

(Increase)/decrease in the fair value of derivative instruments		(13,690	)		25,467
Gain on redemption of debt		(9,706	)		—

Adjusted EBITDA (a)		85,838			55,556

Add/(subtract)
Income tax (expense) benefit		57,597			(566	)
Interest expense, net		(13,637	)		(13,808	)
Provision for losses on accounts receivable		10,310			11,961
(Increase) decrease in accounts receivables		26,657			(28,002	)
(Increase) decrease in inventories		(17,747	)		41,368
Increase (decrease) in customer credit balances		(11,964	)		13,390
Change in deferred taxes		(61,355	)		—
Change in other operating assets and liabilities		2,756			(8,344	)

Net cash provided by (used in) operating activities	$	78,455		$	71,555

Net cash used in investing activities	$	(7,568	)	$	(5,488	)

Net cash used in financing activities	$	(54,535	)	$	(145	)

(a)

•

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

•

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

•

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

•

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

is relevant and useful because it allows investors to view the Partnership’s performance in a manner similar to the method management uses, and makes it easier to compare its results with other companies that have different financing and capital structures. In addition, this measure is consistent with the manner in which the Partnership’s debt covenants in its material debt agreements are calculated. Both the Partnership’s 10.25% Senior Note agreement and its bank credit facility contain covenants that restrict equity distributions, acquisitions, and the amount of debt it can incur. Under the most restrictive of these covenants, which is found in the bank credit facility, the agent bank could step in and control all cash transactions for the Partnership if we failed to comply with the minimum “Availability” or the fixed charge coverage ratio. The Partnership is required to maintain 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 of 1.1x (Adjusted EBITDA being a significant component of this calculation). This method of calculating Adjusted EBITDA may not be consistent with that of other companies and should be viewed in conjunction with measurements that are computed in accordance with GAAP.

•

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.

Fiscal Year Ended September 30, 2008

Compared to the Fiscal Year Ended September 30, 2007

Volume

For fiscal ~~2005~~2008, retail volume of home heating oil decreased 64by 25.35 million gallons, or 116.78%, to ~~487~~351.31 million gallons, as compared to ~~551~~ 376.6 million gallons for fiscal ~~2004~~2007. Volume of other petroleum products declined by 711.63 million gallons, or 918.38%, to 7348.59 million gallons for fiscal 2008 ~~2005,~~ as compared to 8160.12 million gallons for fiscal ~~2004~~2007. An analysis of the change in the retail volume of home heating oil, which is based on management’s estimates, sampling, and other mathematical calculations, ~~(as actual customer consumption patters cannot be precisely determined)~~ is found below:

(in millions of gallons)	Heating Oil ~~Segment~~
Volume—Fiscal 2004	551.6
Volume—Fiscal 2007	376.6
Impact of colder temperatures	4.2
Impact of warmer temperatures	(2.3	)
Impact of acquisitions	3.2
Net customer attrition—retail and commercial	(22.1	)
Net customer attrition	(39.0	)
Acquisitions	13.4
Conservation	(24.5	)
Conservation/Other	(14.5	)(a)
Delivery scheduling	(6.0	)
Change	(25.5	)
Other	(2.2	)
Volume—Fiscal 2008	351.1
Change	(64.3	)
Volume—Fiscal 2005	487.3

~~Total~~(a) ~~degree-days~~Includes inan ~~our~~estimated ~~geographic areas of operations were approximately 0~~3.~~9% greater in fiscal 2005 than in fiscal 2004 and approximately~~ 0~~.5%~~ greater than normal, as reported by NOAA. Due to the significant increase in the price per gallon of home heating oil during the year, we believe that customers are using less home heating oil given similar temperatures. Indications based on internal studies suggest that our customers have reduced their consumption by approximately 4.4%. In addition, we estimate that during fiscal 2005, home heating oil volume was reduced by 6.0 million gallons ~~due~~reclassified to aother ~~delivery~~petroleum ~~scheduling~~product ~~variance~~sales.

Temperatures in our geographic areas of operations for 2008 were 0.5% warmer than fiscal 2007 and 6.2% warmer than normal, as reported by NOAA. For fiscal 2008, net customer attrition was 4.4%. Due to the significant increase in the price per gallon of home heating oil over the last several years, we believe that customers are using less home heating oil given similar temperatures when compared to prior periods and this decrease is reflected in the “Conservation/Other” heading in the above table.

The percentage of home heating oil volume sold to our residential variable price customers who are our highest margin customers decreased to 42.9% of total home heating oil volume sales for fiscal 2008, as compared to 45.9% for fiscal 2007. Accordingly, the percentage of home heating oil volume sold to residential price-protected customers increased to 42.4% for fiscal 2008, as compared to 37.7% for fiscal 2007. For fiscal 2008, sales to commercial/industrial customers represented 14.7% of total home heating oil volume sales, as compared to 16.5% for fiscal 2007.

Product Sales

For fiscal ~~2005~~2008, product sales increased $~~149~~265.83 million, or 1624.34%, to $1~~,071~~.354 ~~million~~billion, as compared to $~~921~~1.4089 ~~million~~billion for fiscal ~~2004~~2007, as ~~increases in selling prices more than offset~~ a ~~decline in product sales due to~~ ~~lower volume sold~~33.7% ~~Selling prices during fiscal 2005 were higher due to the~~ increase in ~~wholesale~~home ~~supply~~heating ~~costs.~~oil ~~Average wholesale supply costs were $1.40 per total gallon for fiscal 2005, as compared to $0.94 per total gallon for fiscal 2004. The weighted average~~ selling ~~price~~prices ~~per total gallon~~ was ~~$1.91~~reduced ~~per~~by ~~total~~the ~~gallon in fiscal 2005 compared to $1~~6.468% ~~per~~decrease ~~total gallon~~ in ~~fiscal 2004. Average~~ home heating oil ~~prices increased from $1~~volume.49 ~~per gallon in fiscal 2004 to $1.94 per gallon in fiscal 2005.~~

Installation, ~~Service~~ and ~~Other~~ Service Sales

For fiscal ~~2005~~2008, installation, ~~service~~ and ~~other~~service sales increased $410.6 million, or 2.5.9%, to $~~188~~189.21 million, as compared to $~~183~~178.65 million infor fiscal ~~2004~~2007, asdue ato ~~decline~~an increase in installation ~~and other~~ sales of $24.86 million ~~was~~and ~~offset by~~ an increase in service ~~revenues~~revenue of $76.40 million~~. Over the last several years~~, welargely ~~have~~from ~~modified service plans and billing strategies, in order to maximize service revenue~~acquisitions.

Cost of Product

For fiscal ~~2005~~2008, cost of product increased $~~193~~276.94 million, or 3234.73%, to $~~786~~1.3082 ~~million~~billion, as compared to $~~592~~805.4 million for fiscal ~~2004.~~2007, ~~This~~as is the ~~result of an increase in the average wholesale product cost of $0~~6.~~46 per total gallon, or 49~~8 %, todecrease anin ~~average~~home ofheating ~~$1.40~~oil ~~per~~volume ~~total~~was ~~gallon~~more ~~for~~than ~~fiscal~~offset ~~2005,~~by ~~from~~higher ~~an average of $0.94~~ per ~~total~~ gallon ~~for fiscal 2004. Average~~ wholesale ~~home heating oil~~ product cost ~~increased by $0.46 per gallon to an average of $1.38 per gallon~~ for ~~fiscal~~home ~~2005,~~heating ~~from~~oil ~~an average~~ of $045.~~92 for fiscal 2004~~7%.

We35 believe that the changes 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 changes in the market value of hedges before the settlement of the underlying transaction. Home heating oil margins decreased by $0.0159 per gallon

toGross $Margin 0.5575 per gallon in fiscal 2005 from $ 0.5734 per gallon in fiscal 2004. In an effort to reduce net customer attrition, we delayed increasing our selling price to certain customers whose price plan agreements expired during the July to September 2004 time period. This decision negatively impacted gross profit by an estimated $2.8 million in fiscal 2005, primarily during the first quarter of fiscal 2005.

~~During~~The ~~fiscal~~table ~~2005,~~below ~~product~~recalculates ~~cost was adversely impacted by $3.4 million due to a delay in hedging~~ the ~~price~~Partnership’s ofper ~~product~~gallon ~~for certain~~margins ~~residential~~and ~~protected~~reconciles ~~price customers due to cash constraints under our previous credit agreement. Cost of~~ product ~~was~~gross ~~also~~profit ~~adversely impacted by $1.6 million associated with not hedging the price of product~~ for ~~certain~~home ~~residential~~heating ~~price protected~~oil ~~customers~~and ~~that~~other ~~were~~petroleum ~~incorrectly coded as variable customers~~products. ~~This coding error was corrected in December 2004.~~ Home heating oil ~~per gallon~~ margins for ~~the~~fiscal ~~year~~2008 increased ~~ended~~modestly ~~September 30, 2005 declined~~ by 5.$0.0216 ~~cents~~ per gallon, ~~compared~~or ~~to fiscal~~3.0%, ~~2004 due~~ to an$0.7413 ~~increase~~per ingallon, ~~the~~from ~~percentage~~$0.7197 ofper ~~volume~~gallon ~~sold~~in tofiscal ~~lower~~2007. ~~margin~~We ~~residential~~believe ~~price protected customers,~~ the ~~delay~~change in ~~increasing~~home ~~the~~heating ~~selling~~oil ~~price~~margins toshould ~~customers~~be ~~whose~~evaluated ~~price~~before ~~plans expired during~~ the ~~July~~effects toof ~~September~~increases ~~2004~~or ~~time~~decreases ~~period~~in ~~and~~ the ~~aforementioned~~fair ~~hedging~~value ~~issues~~of derivative ~~concerning~~instruments, ~~price~~as ~~protected~~we ~~customers.~~believe ~~Gross~~that ~~profit~~realized ~~from~~per ~~product~~gallon ~~sales~~margins ~~decreased~~should bynot ~~$44.0~~include ~~million~~the inimpact ~~fiscal~~of ~~2005~~non-cash ~~when~~changes ~~compared~~in tothe ~~fiscal~~market ~~2004~~value ~~due~~of tohedges ~~lower~~before ~~sales~~the ~~volume~~settlement of ~~$37.4~~the ~~million~~underlying ~~and~~transaction. ~~lower~~Product ~~per~~sales ~~gallon~~and ~~margins~~cost of ~~$6.7~~ ~~million~~product ~~(which~~include home ~~includes~~heating ~~$2.8~~oil, ~~million~~other ~~delay~~petroleum inproducts ~~price~~and ~~increases~~liquidated ~~previously~~damages ~~described)~~billings.

The percentage of home heating oil volume sold to residential protected price customers increased to approximately 48% of total home heating oil volume sales during fiscal 2005, as compared to 43% for fiscal 2004. Accordingly, the percentage of home heating oil volume sold to residential variable customers decreased to approximately 36% for fiscal 2005, as compared to 40% for fiscal 2004. During fiscal 2005, sales to commercial/industrial customers represented approximately 16% of total home heating oil volume sales, unchanged from fiscal 2004. Rising energy costs have increased consumer interest in price protection.


	Fiscal Year Ended
	September 30, 2008				September 30, 2007
	Amount (000)		Per Gallon		Amount (000)		Per Gallon
Home Heating Oil
Volume (in millions of gallons)		351.1				376.6

Sales	$	1,198.6	$	3.4137	$	961.9	$	2.5540
Cost		938.3		2.6724		690.9		1.8343

Gross Profit	$	260.3	$	0.7413	$	271.0	$	0.7197


	Amount (000)		Per Gallon		Amount (000)		Per Gallon
Other Petroleum Products
Volume (in millions of gallons)		48.9				60.2

Sales	$	155.3	$	3.1761	$	126.7	$	2.1044
Cost		143.5		2.9343		114.6		1.9031

Gross Profit	$	11.8	$	0.2418	$	12.1	$	0.2013


	Amount (000)				Amount (000)		Change
Total Product
Sales	$	1,353.9			$	1,088.6	$	265.3
Cost		1,081.8				805.4		276.4

Gross Profit	$	272.1			$	283.2	$	(11.1	)

~~Change~~For infiscal 2008, total product gross profit decreased by $11.1 million to $272.1 million, as compared to $283.2 million for fiscal 2007, as the ~~Fair~~increase ~~Value~~due to higher home heating oil per gallon margins of ~~Derivative~~$7.6 ~~Instruments~~million was reduced by the impact of lower home heating oil volume of $18.4 million and a reduction in gross profit from other petroleum products of $0.3 million.

In the summers of fiscal 2005 and fiscal 2004, home heating oil prices increased which resulted in the recording of unrealized gains at the close of both fiscal 2005 and fiscal 2004. The net gain for fiscal 2005 exceeded the gain for fiscal 2004 by $6.1 million. Home heating oil prices were relatively stable in the summer of 2003 and we recorded a small change in the value of derivative instruments. The increase in home heating oil prices in the summer of 2004 is the main driver of the change in the fair value of derivative instruments in fiscal 2004 of $25.8 million.

Cost of Installations and Service

For fiscal ~~2005~~2008, cost of installations and service decreased $70.5 3 million, or 30.62%, to $~~197~~175.48 million, as compared to $~~204~~176.91 million for fiscal 2007, ~~2004.~~as ~~This~~an ~~reduction~~increase ~~was~~in ~~due to a lower level of variable~~ installation costs of $25.0 million ~~attributable~~was toreduced ~~the~~by lower ~~level~~service expenses of ~~installation sales and a~~ $5.53 million ~~decline~~. inInstallation ~~service~~costs ~~expenses~~were higher largely due to acquisition related installation sales. Service expenses ~~decreased~~were lower due to aour ~~contraction~~continued efforts into ~~costs~~control ~~resulting~~our ~~from~~service ~~servicing~~department expenses and a ~~smaller~~reduction in our customer base,. ~~warmer~~The ~~temperatures~~gross ~~during~~profit ~~the~~realized ~~peak~~from ~~heating~~service ~~season~~and installations was $13.4 million for fiscal 2008, ~~which~~as ~~reduced~~compared ~~the~~to ~~frequency~~$2.4 ofmillion ~~service~~for ~~calls~~fiscal 2007. Again, ~~and~~this ~~an improvement~~increase in service ~~the~~gross ~~scheduling~~profits ofwas ~~preventative~~largely ~~maintenance~~driven ~~service~~by ~~calls~~acquisition ~~which~~activity. ~~lowered~~Installation ~~overtime~~costs ~~hours~~were $64.5 ~~The~~million, ~~loss~~or ~~realized~~86.0% ~~from~~of ~~service~~installation ~~(including~~sales ~~installations)~~during ~~improved~~fiscal by2008, and were $1259.15 million, ~~from~~or a84.5% of installation sales during fiscal 2007. Service expenses decreased to $21111.3 million, ~~loss~~or ~~for~~97.5% ~~fiscal~~of ~~2004~~service tosales, aduring fiscal 2008, from $9116.26 million ~~loss~~in fiscal 2007, or 107.8% of service sales. Service costs as a percentage of total service revenue declined as the Partnership continued to increase its rates for ~~fiscal~~service ~~2005~~billings and further reduced its service costs.

(Increase) Decrease in the Fair Value of Derivative Instruments

During fiscal 2007, the increase in the fair value of derivative instruments resulted in the recording of a $15.7 million net credit due to the expiration of certain hedged positions or their realization to cost of product ($14.4 million), and an increase in market value for unexpired hedges ($1.3 million).

Delivery and Branch Expenses

For fiscal ~~2005~~2008, delivery and branch expenses ~~decreased~~increased $113.41 million, or 06.6%, to $~~231~~211.69 million, as compared to $~~233~~198.0 8 million offor ~~expenses incurred in~~ fiscal ~~2004~~2007. ~~Bad~~During ~~debt~~fiscal ~~expense~~2007, ~~credit card processing fees and collection expenses all increased, primarily due to~~ the ~~increase~~Partnership inrecorded ~~product sales dollars~~$4.3 ~~Delivery~~million ~~costs~~of ~~were~~proceeds ~~also~~received ~~higher~~under ~~due~~our toweather ~~the~~hedge ~~rise~~contract, inwhich ~~vehicle~~reduced ~~fuel~~operating ~~costs~~expenses. InWhile ~~total,~~temperatures ~~delivery~~for ~~and~~fiscal ~~branch~~2008 ~~expenses~~were ~~increased~~similar ~~by $4.9 million due~~ to ~~the~~fiscal ~~increase~~2007, inwe ~~bad~~did ~~debt expense,~~not ~~credit~~record ~~card~~any ~~processing~~weather ~~fees,~~hedge ~~collection~~benefit ~~expenses,~~during ~~and~~fiscal ~~fuel costs~~2008. ~~Delivery~~The ~~and~~Partnership’s ~~branch~~weather ~~expenses~~hedge ~~also~~contract ~~increased~~in byplace ~~approximately~~for ~~$5.9~~fiscal ~~million~~2008 ~~due to wage~~ and ~~benefit~~fiscal ~~increases.~~2007 ~~These~~covered ~~delivery~~the ~~and~~period ~~branch~~from ~~expense~~November ~~increases were offset by a reduction in operating costs due~~ to ~~the~~February 28/29, ~~variable~~as ~~nature~~one ofperiod ~~certain~~taken ~~delivery and operating expenses such~~ as ~~direct~~a ~~delivery expense, which decreased with lower volume~~whole. OnTemperatures afor ~~cents~~the four ~~per~~months ~~gallon~~ended ~~basis~~February 28, ~~operating~~2007 ~~costs~~were ~~increased~~approximately 54.~~3 cents per gallon, or 12.6~~0%, ~~from 42.2~~warmer ~~cents~~than ~~per~~the ~~gallon~~weather ~~for~~hedge ~~fiscal~~contract ~~2004~~strike toprice, ~~47.5~~triggering ~~cents~~a ~~per gallon for fiscal 2005~~payment. ~~The~~For ~~5.3~~the ~~cents~~four ~~per~~months ~~gallon~~ended ~~increase~~February 29, ~~was due to higher bad debt and collection expenses~~2008, ~~wage~~temperatures ~~and~~were ~~benefit~~colder ~~increases,~~than ~~and~~ the ~~inability~~weather tohedge ~~reduce certain fixed expenses~~contract ~~commensurate~~strike ~~with~~price, aresulting ~~reduction~~ in ~~home~~no ~~heating oil volume of 11~~payout.~~7%.~~

Exclusive of the weather hedge benefit in 2007, delivery and branch expenses increased $8.8 million, or 4.3%. Delivery and branch expenses were reduced by an estimated $5.7 million due to the volume decline before acquisitions, but were more than offset by increased delivery and branch expenses from the stand-alone acquisitions ($9.5 million) and higher bad debt expense ($6.2 million). Bad debt expense rose due to a higher level of sales, a modest increase in the write-off rates, lower recoveries on accounts previously written off and an increase in the reserve for future write-offs. On a cents per gallon basis (excluding the impact of weather insurance and acquisitions), delivery and branch expenses increased 6.0 cents per gallon, or 11.1%, from 54.0 cents per gallon for fiscal 2007 to 60.0 cents per gallon for fiscal 2008, due to the fixed nature of certain delivery and branch expenses, the increase in bad debt expense and wage and benefit increases.

Depreciation and Amortization

For fiscal ~~2005~~2008, depreciation and amortization expenses declined by $12.82 million, or 47.96%, to $3526.58 million, as compared to $3729.30 million for fiscal ~~2004~~2007. Amortization expense was lower by $1.2 million, as acquisitions from fiscal 2001 with 7 year lives became fully amortized in fiscal 2008. Depreciation expenses declined by $1.2 million as ~~certain~~capital ~~assets,~~expenditures ~~which~~for ~~were~~technology ~~not~~acquired ~~replaced,~~in fiscal 2003 became fully depreciated.

General and Administrative Expenses

~~During~~For fiscal ~~2005~~2008, general and administrative expenses ~~increased~~decreased by $230.73 million, or ~~121.~~1.8%, to $4318.21 million, as compared to $1918.5 4 million for fiscal ~~2004~~2007 largely due to ~~$7.5~~lower ~~million~~compensation inexpense ~~bridge financing fees, $4.4 million of legal expenses incurred~~ relating to ~~defending~~the ~~several~~Partnership’s ~~purported~~profit ~~class~~sharing ~~action lawsuits, legal and professional fees associated with exploring several refinancing alternatives, legal expense attributable to inquiries from regulatory agencies, $3~~plan.~~4 million~~ ofIn ~~expenses and fees associated with certain bank amendments and waivers on our previous credit facility obtained during the first~~ fiscal ~~quarter of 2005~~2008, anAdjusted ~~increase~~EBITDA indecreased ~~officers~~by ~~and directors insurance of~~ $112.19 million, to $455.16 million, ~~in expenses~~which ~~for~~drove ~~compliance~~the ~~with~~decrease ~~Sarbanes-Oxley, $3.8 million~~ in profit sharing expense. ~~relating~~The toPartnership ~~separation~~accrues ~~agreements~~approximately ~~entered~~6% ~~into~~of ~~with~~Adjusted ~~certain~~EBITDA, ~~former~~as ~~executives~~defined ~~and~~in ~~$1.7~~the ~~million~~profit ~~higher~~sharing ~~compensation~~plan ~~expense~~for ~~associated~~distribution ~~with~~to ~~unit~~its ~~appreciation rights~~employees. ~~(In~~If ~~fiscal~~Adjusted ~~2004 and~~EBITDA ~~fiscal 2005~~increases, the ~~decline~~dollar inamount ~~the~~of ~~unit price for senior subordinated units resulted in~~ the ~~reversal~~profit ofsharing ~~previously~~pool ~~recorded~~will ~~expenses of $3~~increase.9 ~~million~~On ~~and~~the ~~$2.2 million~~other hand, ~~respectively.)~~if ~~Partially~~Adjusted ~~offsetting~~EBITDA ~~these~~decreases, ~~increases~~the ~~were~~dollar ~~lower~~amount ~~business process improvement expenses~~ of ~~$1.4~~the ~~million~~profit ~~and~~sharing apool ~~reduction~~will inbe ~~compensation and benefit expense of $1~~less.2 ~~million.~~

~~Goodwill~~Operating ~~Impairment~~Income ~~Charge~~

~~During~~For ~~the second quarter of~~ fiscal ~~2005~~2008, aoperating ~~number~~income ofdecreased ~~events~~$51.8 ~~occurred~~million ~~that~~to ~~indicated~~$3.3 amillion, ~~possible~~as ~~impairment~~compared ofto ~~goodwill~~$55.1 ~~might~~million ~~exist.~~for ~~These~~fiscal ~~events~~2007, ~~included our~~as ~~determination~~an improvement in service ~~February~~profitability ~~2005~~ of ~~significantly~~$11.0 ~~lower~~million ~~than~~was ~~expected~~reduced ~~operating~~by ~~results~~the ~~for~~decrease ~~fiscal 2005 and a significant decline~~ in the ~~Partnership’s~~fair ~~unit~~value ~~price.~~of Asderivative ainstruments ~~result~~ of ~~these~~$41.2 ~~triggering~~million, ~~events~~an ~~and~~increase ~~circumstances,~~in webad ~~completed~~debt ~~an interim~~expense ~~SFAS~~of No$6. ~~142~~2 ~~impairment~~million, ~~review with~~ the ~~assistance~~absence of a ~~third~~weather ~~party~~insurance ~~valuation~~benefit ~~firm as~~ of ~~February 28, 2005~~$4.3 ~~This~~million ~~review~~and ~~resulted~~a decline in aproduct ~~non-cash~~gross ~~goodwill~~profit ~~impairment charge~~ of ~~approximately~~ $6711.01 million~~, which reduced the carrying amount of goodwill~~.

Operating Income (Loss)

For fiscal 2005, operating income decreased $139.2 million to a loss of $95.4 million, compared to $43.7 million in operating income for fiscal 2004. The decrease in our operating income in fiscal 2005 is the result of a $67.0 million non-cash goodwill impairment charge, as described above, lower gross profit from the sale of petroleum products of $44.0 million, increases in general and administrative expense totaling $23.7 million and the impact of comparative change in the fair value of derivative instruments of $19.7 million offset in part by an increase in service profitability of $12.1 million, decreases in branch and delivery expenses of $1.4 million and depreciation and amortization of $1.8 million.

Interest Expense

~~During~~For fiscal ~~2005~~2008, interest expense ~~decreased~~increased $30.92 million, or 91.80%, to $3620.27 million, as compared to $4020.15 million ~~for~~in fiscal ~~2004~~2007. This ~~change was due to the impact of lower average debt outstanding offset by an~~ increase inresulted ~~our~~from ~~weighted~~higher average ~~interest rate during fiscal 2005. Total debt outstanding declined because a portion of the proceeds from the propane sale, were used in part to repay debt. Average~~ working capital borrowings ~~were higher in fiscal 2005 due principally to the increase in wholesale product cost~~.

Interest Income

~~During~~For fiscal ~~2005~~2008, interest income ~~increased~~decreased by $02.90 million, ~~or 27.3%,~~ to $46.39 million, as compared to $38.49 million for fiscal ~~2004~~2007, ~~due~~as ~~principally~~a toreduction ~~higher~~in ~~average~~interest income due to lower invested cash balances and lower interest rates were partially offset by an increase in finance charge income on higher past due accounts receivable balances.

Amortization of Debt Issuance Costs

For fiscal ~~2005~~2008, amortization of debt issuance costs ~~decreased $0.9~~was ~~million, or 27.0%, to~~ $2.53 million, ~~compared~~unchanged tofrom ~~$3.5 million for~~ fiscal ~~2004~~2007.

~~Loss~~Income onTax ~~Redemption~~Expense ~~of Debt~~

~~During~~For ~~the first quarter of~~ fiscal ~~2005~~2008, weincome ~~recorded~~tax aexpense ~~loss~~decreased ofby $~~42.~~1.4 million onto ~~the early redemption of certain notes at the heating oil and propane segments~~$0.6 ~~The~~million, ~~loss~~as ~~consisted~~compared ofto ~~cash~~income ~~premiums~~tax ~~paid~~expense of $372.0 million for ~~early~~fiscal ~~redemption, the write-off of previously capitalized net deferred financing costs of $6~~2007.1 ~~million~~The ~~and legal expenses of~~ $01.74 million, ~~reduced~~decrease inwas ~~part~~due byto the ~~realization~~decline ~~of the~~in ~~unamortized~~estimated ~~portion~~taxable ofincome afor ~~$1.7~~2008 ~~million basis adjustment to the carrying value of long-term debt~~versus 2007.

~~Income~~Loss ~~Tax~~on ~~Expense~~Sale ~~(Benefit)~~of Segments

~~Income~~For ~~tax expense for~~ fiscal ~~2005~~2007, ~~was~~we ~~approximately~~recorded ~~$0.7~~a ~~million~~charge ~~compared~~of to $1.21 million inrelating ~~fiscal~~to ~~2004.~~a ~~The~~purchase ~~decrease~~price ofadjustment ~~approximately~~for ~~$0.5 million is~~ the ~~result~~sale of ~~increases~~the inpropane ~~state capital taxes of $0~~segment.5 ~~million~~There inwas ~~fiscal~~no ~~2005,~~similar ~~which~~charge isrecorded ~~more than offset by $1.0 million~~ in ~~tax~~fiscal ~~benefits that were fully utilized against taxes associated with the gain on the sale of the propane segment~~2008.

28Net Income (Loss)

For fiscal 2008, a net loss of $13.4 million was recorded, as compared to net income of $38.2 million for fiscal 2007. This decrease of $51.6 million was due to a $51.8 million decrease in operating income and an increase in net interest expense of $2.3 million, reduced by lower income tax expense of $1.4 million and the change in loss on sale of discontinued operations of $1.1 million. The decrease in operating income largely resulted from a $41.2 million change in the fair value of derivative instruments from a $15.7 million non-cash gain in fiscal 2007 to a $25.5 million non-cash loss in fiscal 2008.

Adjusted EBITDA

For fiscal 2008, Adjusted EBITDA decreased by $12.9 million, to $55.5 million, as compared to $68.4 million for fiscal 2007, due to the decline in volume, the absence of a weather insurance benefit ($4.3 million) and higher bad debt expense ($6.2 million).

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


	Fiscal Year Ended September 30,
(in thousands)	2008			2007
Income (loss) from continuing operations	$	(13,408	)	$	39,302
Plus:
Income tax expense		566			2,002
Amortization of debt issuance cost		2,339			2,282
Interest expense, net		13,808			11,525
Depreciation and amortization		26,784			28,995

EBITDA (a) from continuing operations		30,089			84,106
(Increase)/decrease in the fair value of derivative instruments		25,467			(15,664	)

Adjusted EBITDA (a)		55,556			68,442

Add/(subtract)
Income tax expense		(566	)		(2,002	)
Interest expense, net		(13,808	)		(11,525	)

Income (Loss) From Continuing Operations


Provision for losses on accounts receivable		11,961			5,726
(Increase) decrease in accounts receivables		(28,002	)		5,761
(Increase) decrease in inventories		41,368			(8,222	)
Increase (decrease) in customer credit balances		13,390			(3,724	)
Change in other operating assets and liabilities		(8,344	)		(3,341	)

Net cash provided by (used in) operating activities	$	71,555		$	51,115

Net cash used in investing activities	$	(5,488	)	$	(29,254	)

Net cash used in financing activities	$	(145	)	$	(96	)

~~For~~(a) ~~fiscal~~EBITDA ~~2005~~(Earnings ~~the loss~~ from continuing operations ~~increased~~before ~~$174.9~~net ~~million~~interest ~~to a loss of $172.6 million~~expense, ~~compared to~~ income ~~of $2.3 million for fiscal 2004~~taxes, asdepreciation ~~the~~and ~~decline~~amortization) ~~in operating income of $139.2 million~~ and ~~the~~Adjusted ~~loss~~EBITDA onare ~~the~~non-GAAP ~~redemption~~financial ofmeasures ~~debt~~that ofare ~~$42.1~~used ~~million~~as ~~were~~supplemental ~~reduced~~financial measures by ~~lower~~management ~~interest~~and ~~expense~~external users of ~~$3.9~~our ~~million~~financial statements, ~~higher~~such ~~interest~~as ~~income of $0.9 million~~investors, ~~lower~~commercial ~~amortization~~banks ~~of debt issuance costs of $0.9 million~~ and aresearch ~~decrease~~analysts, into ~~income tax expense of $0.5 million.~~ assess:

~~Income~~• ~~(Loss)~~our ~~From~~compliance ~~Discontinued~~with ~~Operations~~certain financial covenants included in our debt agreements;

~~For~~• ~~fiscal~~our ~~2005,~~financial ~~income~~performance ~~from~~without ~~discontinued~~regard ~~operations~~to ~~decreased~~financing ~~$28.4 million. Income from the discontinued propane segment~~methods, ~~which~~capital ~~was sold on December 17~~structure, ~~2004, generated $21.3 million in net~~ income ~~for~~taxes ~~fiscal~~or ~~2004~~historical ~~and~~cost ~~a net loss of $6.2 million for fiscal 2005. The discontinued TG&E segment was sold on March 31, 2004 and generated net income of $0.9 million for fiscal 2004.~~ basis;

~~Gain~~• our ability to generate cash sufficient to pay interest on ~~Sales~~our ofindebtedness ~~Discontinued~~and ~~Operations~~to make distributions to our partners;

~~During~~• ~~fiscal~~our ~~2005,~~operating weperformance ~~recorded~~and areturn ~~gain~~ on ~~the~~invested ~~sale~~capital ofas ~~the~~compared ~~propane~~to ~~segment~~those ~~totaling~~of ~~approximately~~other ~~$156.8~~companies ~~million,~~in ~~which~~the isretail ~~net~~distribution of ~~income~~refined ~~taxes~~petroleum ofproducts ~~$1.3~~business, ~~million.~~without ~~The~~regard ~~purchase~~to ~~price~~financing ~~for~~methods ~~the TG&E segment was also finalized in fiscal 2005~~ and a ~~positive~~capital ~~adjustment~~structure; ~~of $0.8 million was recorded.~~ and

~~Net~~• ~~loss~~the viability of acquisitions and capital expenditure projects and the overall rates of return of alternative investment opportunities.

~~For~~Adjusted ~~fiscal~~EBITDA ~~2005~~is a non-GAAP financial measure that is calculated as earnings from continuing operations before net interest expense, income taxes, depreciation and amortization, (increase) decrease in the ~~net~~fair value of derivatives, loss ~~increased~~on ~~$45~~debt redemption, goodwill impairment, and other non-cash and non-operating charges.2 ~~million~~Management believes the presentation of this measure is relevant and useful because it allows investors to view the Partnership’s performance in a ~~net~~manner ~~loss~~similar ofto ~~$21.2~~the ~~million~~method management uses, ~~compared~~and makes it easier to acompare ~~net~~its ~~income~~results ofwith ~~$24.0~~other ~~million~~companies ~~incurred~~that inhave different ~~fiscal~~financing ~~2004~~and capital structures. In addition, asthis measure is consistent with the ~~decline~~manner in ~~operating~~which ~~income~~the ~~(loss)~~Partnership’s ~~from~~debt ~~continuing operations~~covenants ofin ~~$174~~its material debt agreements are calculated.9 ~~million~~Both the Partnership’s 10.25% Senior Note agreement and its bank credit facility contain covenants that restrict equity distributions, acquisitions, and the ~~reduction~~amount inof ~~income~~debt ~~from~~it ~~discontinued~~can ~~operations~~incur. Under the most restrictive of ~~$28.4~~these ~~million~~covenants, ~~were~~which ~~partially~~is ~~offset~~found byin the ~~gain~~bank oncredit facility, the ~~sale~~agent ofbank could step in and control all cash transactions for the ~~propane~~Partnership ~~segment~~if we failed to comply with the minimum availability or the fixed charge coverage ratio. The Partnership is required to maintain either availability (borrowing base less amounts borrowed and ~~TG&E~~letters ~~segment~~of credit issued) of $~~157~~43.65 million or a fixed charge coverage ratio of 1.1x (Adjusted EBITDA being a significant component of this calculation). This method of calculating Adjusted EBITDA may not be consistent with that of other companies and should be viewed in conjunction with measurements that are computed in accordance with GAAP.

~~Earnings~~Each ~~From~~of ~~Continuing~~EBITDA ~~Operations~~and Adjusted ~~Before~~EBITDA ~~Interest,~~has ~~Taxes~~its limitations as an analytical tool, ~~Depreciation~~and it should not be considered in isolation or as a substitute for analysis of our results as reported under GAAP. Some of the limitations of EBITDA and ~~Amortization~~Adjusted (EBITDA) are:

~~For~~• ~~fiscal 2005,~~ EBITDA ~~decreased~~and ~~$183.1~~Adjusted ~~million to an EBIDTA loss of $102.0 million, as compared to $81.1 million in~~ EBITDA ~~for~~do ~~fiscal~~not ~~2004.~~reflect ~~For~~our ~~fiscal 2005, EBITDA was reduced by $67.0 due to a goodwill impairment charge and $42.1 million due to the non~~ cash ~~loss~~used for ~~the~~capital early redemption of debt for fiscal 2005, EBITDA was favorably impacted by $6.1 million due to the change in the fair value of derivative instruments. For fiscal 2004, EBITDA was favorably impacted by $25.8 million due to the change in the fair value of derivative instruments. expenditures;

~~EBITDA~~• ~~should~~Although ~~not~~depreciation beand ~~considered~~amortization asare annon-cash ~~alternative~~charges, tothe ~~net~~assets ~~income~~being ~~(as~~depreciated ~~an indicator of operating performance)~~ or asamortized anoften ~~alternative~~will tohave ~~cash flow (as a measure of liquidity or ability~~ to ~~service~~be ~~debt obligations)~~replaced, ~~but provides~~and ~~additional~~EBITDA ~~information~~and ~~for~~Adjusted ~~evaluating~~EBITDA ~~our~~do ~~ability~~not toreflect ~~make~~ the ~~minimum~~cash ~~quarterly~~requirements ~~distribution. EBITDA is calculated~~ for ~~the~~such ~~fiscal years ended September 30 as follows:~~ replacements;

	Fiscal Year Ended September 30,
(in thousands)	2005			2004
	(restated)			(restated)
Loss from continuing operations	$	(172,580	)	$	2,335
Plus:
Income tax expense		696			1,240
Amortization of debt issuance costs		2,540			3,480
Interest expense, net		31,838			36,682
Depreciation and amortization		35,480			37,313
EBITDA		(102,026	)		81,050
Add/(subtract)
Income tax expense		(696	)		(1,240	)
Interest expense, net		(31,838	)		(36,682	)
Unit compensation expense (income)		(2,185	)		(4,382	)
Provision for losses on accounts receivable		9,817			7,646
Gain on sales of fixed assets, net		(43	)		(281	)
Goodwill impairment charge		67,000			—
Loss on redemption of debt		42,082			—
Unrealized (gains) losses on derivative contracts		(6,081	)		(25,811	)
Change in operating assets and liabilities		(30,945	)		(6,631	)
Net cash provided by (used in) operating activities	$	(54,915	)	$	13,669

•

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

29• 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.

LIQUIDITY AND CAPITAL RESOURCES

Our ability to satisfy our 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 factors, most of which are beyond our control. ~~See~~ (see Item 1A — “Risk Factors).” Capital requirements, at least in the near term, are expected to be provided by cash flows from operating activities, cash on hand at September 30, ~~2006~~2009 or a combination thereof. To the extent future capital requirements exceed cash on hand plus cash flows from operating activities, we anticipate that working capital will be financed by our revolving credit facility, as discussed below, and repaid from subsequent seasonal reductions in inventory and accounts receivable.

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

~~For~~Due ~~fiscal~~to ~~2006,~~the ~~cash~~seasonal ~~provided~~nature byof ~~operating~~the ~~activities~~home ~~was~~heating ~~$18.4 million~~oil business, ascash ~~compared~~is togenerally ~~cash~~ used in ~~operating~~operations ~~activities~~during ofthe ~~$54.9~~winter ~~million~~(our ~~for~~first ~~fiscal 2005.~~and ~~The~~second ~~change~~fiscal ofquarters) ~~$73.3~~as ~~million~~customers ~~was~~receive ~~largely~~deliveries ~~due~~and topay anfor ~~increase~~products inpurchased ~~operating~~within ~~income~~our ofpayment ~~$5.2~~terms, ~~million~~and ~~(before~~cash ~~the~~is ~~non~~generally ~~cash~~provided ~~goodwill~~by ~~impairment~~operating ~~charge~~activities during ofthe ~~$67.0~~spring ~~million~~and ~~recorded~~summer in(our ~~June~~third ~~2005)~~ and ~~lower~~fourth ~~cash~~quarters) ~~requirements~~when tocustomer ~~finance~~payments ~~accounts~~exceed ~~receivable of $10~~deliveries.0 ~~million.~~ During fiscal ~~2006~~2009, ~~the~~we ~~increase~~generated ~~in accounts receivable was~~ $378.85 million ~~or $10.0 million less than the comparable increase~~ in ~~accounts~~cash ~~receivable~~flow atfrom ~~September 30,~~operating ~~2005 of $13.8 million~~activities, aswhich ~~the increase in sales of $37.0 million in fiscal 2006 over fiscal 2005~~ was $~~117~~6.49 million ~~less~~higher than the ~~increase experienced in fiscal 2005 of~~ $~~154~~71.46 million ~~compared to fiscal 2004. Generally, accounts receivable collections in fiscal 2006 were favorably impacted by warmer temperatures, which resulted in lower sales~~ of ~~$104.1 million. Net~~ cash used in ~~operating~~operations ~~activities~~for onfiscal a2008. ~~comparable~~This ~~basis~~improvement was ~~negatively impacted by $5.6 million~~ primarily due to ~~an increase in~~ the ~~quantity~~impact of ~~home~~lower ~~heating~~wholesale ~~oil~~product ~~on hand at September 30~~costs, ~~2006~~which ~~versus~~impacts ~~September 30,~~accounts ~~2005.~~receivable ~~During the fourth quarter of fiscal 2006~~collections, ~~we increased our quantity of home heating oil~~ inventory oncosts, ~~hand~~prepaid tohedging ~~take~~costs, ~~advantage~~hedging ofmargin ~~favorable~~requirements, ~~prices~~customer credit inbalances, ~~the~~accounts ~~spot~~payable ~~delivery~~ and ~~futures~~accrued ~~markets~~expenses. AsOur ~~a result,~~cash atflow ~~September 30,~~from ~~2006~~operations ~~inventory~~for ~~increased~~fiscal by2009 ~~11.2 million~~also ~~gallons~~benefited tofrom ~~32.5 million~~higher ~~gallons~~earnings asfrom operations, when compared to ~~September 30,~~fiscal ~~2005~~2008.

While the Partnership generated $78.8 million in cash from operations during fiscal 2009, this amount was reduced by a net increase in operating assets and liabilities of $0.3 million. Accounts receivable declined by $26.7 million largely due to lower wholesale product costs and an improvement in our days sales outstanding. During the summer of fiscal 2009, cash was used to finance an increase in inventories of $17.7 million, as we purchased 18.0 million gallons of home heating oil for our fiscal 2010 fall and winter needs and increased our inventory quantities to 28.5 million gallons as of September 30, 2009, compared to 8.9 million gallons as of September 30, 2008. We increased our inventory levels to take advantage of favorable home heating oil prices in the spot and futures market.

Approximately 34% of our customers are on a budget payment plan and these customers pay their annual estimated heating bill in 12 monthly installments. Typically, these plans begin before the heating season and a liability is created as payments exceed deliveries. In fiscal 2009, we experienced a decline in payments from our budget customers of $12.0 million as compared to fiscal 2008. This change was largely due to the decline in home heating oil prices which reduced the required budget payments for the upcoming heating season.

For fiscal 2008, cash provided by operating activities was $71.6 million, as cash generated from business operations of $53.1 million, lower product inventory purchases of $41.4 million and an increase in customer credit balances of $13.4 million was reduced by an increase in accounts receivable of $28.0 million and other net changes in operating assets and liabilities of $8.3 million. Accounts receivable rose due to an increase in the wholesale cost for home heating oil in fiscal 2008 as compared to fiscal 2007. Inventory levels were lower by $49.6 million, despite higher prices, as we reduced the quantity of home heating oil on hand from 39.4 million gallons as of September 30, 2007 to 8.9 million gallons as of September 30, 2008. At September 30, 2007, we increased our inventory levels to take advantage of favorable prices in the spot and futures market. We increased the monthly budget payment requirements for our budget customers during the summer of fiscal 2008, which provided $13.4 million more in cash at September 30, 2008, when compared to September 30, 2007.

Investing Activities

During fiscal ~~2006~~2009, weour ~~spent~~capital expenditures totaled $5.4.3 million, ~~for~~as ~~fixed~~we ~~assets~~invested in computer hardware and ~~received~~software ($21.24 million), ~~from~~refurbished ~~the~~certain ~~sale~~physical ofplants ($1.0 million) and made additions to ~~certain~~our ~~fixed~~fleet ~~assets~~and other equipment ($1.9 ~~Cash~~million). ~~flow~~We ~~provided~~also bycompleted ~~investing~~one ~~activities~~acquisition ~~was~~for $~~467~~4.30 million ~~for~~and ~~fiscal~~allocated ~~2005,~~$3.4 ~~primarily~~million ~~due~~of the gross purchase to ~~the~~intangible ~~sale~~assets ofand ~~the~~$0.6 ~~propane~~million ~~segment~~to fleet. We paid $ 3.4 million in ~~December~~cash ~~2004~~and assumed net working capital credits of $ 0.6 million.

During fiscal 2008, we spent $4.1 million for fixed assets and received $0.5 million from the sale of certain assets as we invested in computer hardware and software ($1.1 million), refurbished certain physical plants ($1.6 million) and made additions to our fleet and other equipment ($1.4 million). We completed eight acquisitions for $ 2.6 million and allocated $2.2 million of the gross purchase to intangible assets and $0.4 million to fleet. We paid $ 1.9 million in cash and assumed net working capital credits of $ 0.7 million.

During fiscal 2007, we spent $4.9 million for fixed assets and received $1.9 million from the sale of several non essential buildings and other fixed assets, as we invested in computer hardware and software ($0.9 million), refurbished certain physical plants ($1.3 million) and made additions to our fleet and other equipment ($2.7 million). We completed eight acquisitions with a total cash outlay of $26.4 million allocated $22.8 million of the gross purchase to intangible assets, $2.5 million to fleet and $1.1 million to other net assets.

Financing Activities

~~For~~During fiscal ~~2006~~2009, ~~cash flows used in financing activities were $23.1 million, as~~ the ~~$50.2~~Partnership ~~million~~repurchased ~~(net of expenses) raised in our recapitalization along with~~ $4640.3 million ~~borrowed~~face ~~under~~value ~~our~~of ~~revolving~~its ~~credit facility, was used to repay $52~~10.925% ~~million~~Senior ~~previously~~Notes ~~borrowed~~due ~~under~~February ~~the~~2013 ~~revolving~~for ~~credit facility, repay long-term debt of~~ $6630.12 million, and ~~pay~~paid ~~$0.6~~distributions ~~million~~ to ~~amend~~ our ~~bank~~unitholders ~~facility.~~of ~~Cash flows used in financing activities were~~ $~~306~~15.74 million ~~for fiscal 2005~~. During fiscal ~~2005~~2009, ~~$292.2~~we ~~million~~did ofnot ~~cash~~borrow ~~was provided from borrowings~~ under our ~~new~~ revolving credit facility ~~($181.2~~but ~~million)~~had ~~and~~letters-of-credit outstanding ~~previous~~under ~~credit~~the facility ~~($111~~.0 ~~million),~~We ~~which~~also ~~was~~paid ~~used to repay~~ $~~119~~6.06 million ~~borrowed~~in ~~under~~fees for our ~~previous~~new credit agreement and ~~$174.6~~spent ~~million borrowed under the new agreement. Also, during fiscal 2005, we repaid~~ $~~259~~2.53 million into ~~long-term~~purchase ~~debt~~637,285 ~~paid~~common ~~$37.7~~units ~~million~~ in ~~debt~~connection ~~prepayment~~with ~~premiums~~our ~~and~~unit ~~expenses~~repurchase ~~and~~plan ~~paid $8~~program.0 ~~million in fees and expenses related to refinancing our bank credit facilities.~~

AsFor afiscal ~~result of the above activity~~2008, ~~cash~~we ~~decreased~~borrowed byand ~~$8.0~~repaid ~~million, to~~ $9157.12 million asunder ofour ~~September 30,~~revolving ~~2006~~credit facility.

30For fiscal 2007, cash flows used in financing activities were $0.1 million.

FINANCING AND SOURCES OF LIQUIDITY

WeLiquidity have an asset based revolving credit facility with a group of lenders, which provides us with the ability to borrow up to $260 million for working capital purposes (subject to certain borrowing base limitations and ~~coverage~~ ~~ratios)~~Capital ~~including~~Resources the issuance of up to $95 million in letters of credit. From December through March of each year, we can borrow up to $310.0 million. 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. On December 28, 2006, the Partnership obtained a waiver from the lender group which extended the date for the delivery of financial statements for fiscal 2006 to February 15, 2007.

~~Under~~Our ~~the~~ability ~~terms~~to ofsatisfy ~~the~~our ~~revolving~~financial ~~credit~~obligations ~~facility,~~depends weon ~~must~~our ~~maintain~~future atperformance, ~~all~~which ~~times either~~will ~~availability~~be ~~(borrowing~~subject ~~base~~to ~~less~~prevailing ~~amounts~~economic, ~~borrowed~~financial, business and ~~letters~~weather ofconditions, ~~credit~~the ~~issued)~~ability ofto ~~$25.0~~pass ~~million~~on orthe afull ~~fixed~~impact ~~charge~~of ~~coverage~~high ~~ratio~~wholesale ~~(as~~heating ~~defined~~oil inprices ~~the~~to ~~credit~~customers, ~~agreement)~~the effects of ~~not~~high ~~less~~net ~~than~~customer ~~1.1 to 1.0. As of September 30~~attrition, ~~2006,~~conservation ~~availability was~~and ~~$140.2~~other ~~million~~economic and ~~the~~geo-political ~~fixed~~factors, ~~charge~~most ~~coverage~~of ~~ratio~~which ~~was~~are beyond ~~2.65~~our ~~to 1~~control.0. AsIn ofthe ~~September 30,~~near ~~2006~~term, ~~$52.3~~capital ~~million~~requirements inare ~~letters~~expected ofto ~~credit~~be ~~were~~provided ~~outstanding,~~by ~~primarily~~cash ~~for~~flows ~~current~~from ~~and~~operating ~~future~~activities, ~~insurance~~cash ~~reserves.~~on ~~For~~hand ~~fiscal~~at ~~2007~~September 30, we2009 ~~expect~~or toa ~~free-up~~combination ~~$7 million in cash by issuing an additional $4~~thereof.0 ~~million~~To inthe ~~letters~~extent offuture ~~credit~~capital inrequirements ~~connection~~exceed ~~with~~cash on ~~our~~hand ~~insurance~~plus ~~program~~cash ~~and~~flows byfrom ~~issuing~~operating ~~very~~activities, ~~short-term~~we ~~duration~~anticipate ~~(2-5~~that ~~days)~~working ~~letters~~capital ofwill ~~credit~~be ~~from~~financed ~~time~~by toa ~~time to finance~~ our ~~inventory~~revolving ~~purchases~~credit facility.

~~During~~In ~~the~~July ~~first~~2009, ~~half~~we ofentered ~~fiscal~~into ~~2006,~~an weamended ~~purchased~~and ~~futures~~restated ~~contracts~~asset tobased ~~manage~~revolving ~~the~~credit ~~majority~~facility with a group of ~~our~~lenders, ~~exposure~~that toexpires ~~market~~in ~~risk~~July, ~~related~~2012 ~~to changes~~and inwhich provides us with the ~~current~~ability ~~and~~to ~~future~~borrow ~~market~~up ~~price~~to of$240 million ~~home~~($290 million during the heating ~~oil~~season ~~purchased~~from ~~for~~November ~~resale~~through toApril ~~our~~of ~~fixed~~each ~~price~~year) ~~customers.~~for Toworking acapital ~~certain~~purposes ~~extent,~~(subject ~~availability~~to ~~must~~certain beborrowing ~~set~~base ~~aside~~limitations toand ~~respond~~coverage toratios), including the ~~volatile~~issuance ~~home~~of ~~heating~~up ~~oil~~to ~~markets~~$100.0 ~~Futures~~million ~~contracts~~in ~~are~~letters of ~~marked~~credit. toThe ~~market~~Partnership oncan aincrease ~~daily~~the ~~basis~~facility ~~and~~size ~~require~~by an$50 ~~initial~~million ~~cash~~without ~~margin~~the ~~deposit~~consent ~~and~~of ~~potentially~~the ~~require~~bank agroup. ~~daily~~However, ~~adjustment~~the bank group is not obligated to ~~such~~fund ~~cash~~the ~~deposit~~$50 ~~(maintenance~~million ~~margin)~~increase. ~~For~~If ~~example,~~the ~~assuming~~bank ~~100 million~~group ~~gallons~~elects not to fund the increase, athe Partnership ~~30-cent~~can ~~per~~add ~~gallon~~additional ~~decline~~lenders into the ~~market~~ ~~value~~group, with the consent of ~~these~~the ~~hedged~~Agent, ~~instruments~~which ~~(as~~shall wenot ~~experienced~~be ~~from~~unreasonably ~~time-to-time)~~withheld. ~~would~~Obligations ~~create~~under anthe ~~additional~~new ~~cash~~revolving ~~margin~~credit ~~requirement~~facility ofare ~~approximately~~secured ~~$30.0~~by ~~million.~~liens Inon ~~this~~substantially ~~example,~~all ~~availability~~of inour ~~the~~assets ~~short-term~~including accounts isreceivable, ~~reduced~~inventory, asgeneral weintangibles, ~~fund~~real ~~the~~property, ~~margin~~fixtures ~~call~~and equipment. ~~This~~ ~~availability~~During ~~reduction~~this ~~should~~past beheating ~~temporary~~season, as we ~~should~~did benot ~~able~~borrow tounder ~~purchase~~our ~~product~~previous atcredit afacility. ~~later~~As ~~date~~of ~~for~~ September 30, ~~cents~~2009, a$40.9 ~~gallon~~million ~~less~~in ~~than~~letters ~~the~~of ~~anticipated~~credit ~~strike~~were outstanding, ~~price~~of ~~when~~which ~~the~~$39.3 ~~agreement~~million ~~with~~are ~~the~~for ~~price-protected~~current ~~customer~~and ~~was~~future ~~entered~~insurance ~~into.~~reserves Aand ~~spike~~bonds ~~in wholesale~~and ~~heating~~$1.6 ~~oil~~million ~~prices~~are ~~could~~for ~~also~~seasonal ~~reduce~~inventory ~~availability,~~purchases asand weother ~~must~~working ~~finance~~capital apurposes. ~~portion~~We ofbelieve that our ~~inventory~~reliance ~~and~~on ~~accounts~~letters ~~receivable~~of ~~with~~credit ~~internally~~for ~~generated~~inventory purposes ~~cash~~will asbe ~~the~~reduced ~~net~~in ~~advance~~fiscal ~~for~~2010 ~~eligible~~as ~~accounts~~we ~~receivable~~have isincreased ~~85%~~our ~~and~~trade ~~40%~~credit to ~~80%~~over of$24.0 ~~eligible inventory~~million.

~~Since~~Under the ~~beginning~~terms of the credit ~~second half of fiscal 2006~~facility, we ~~have~~must ~~entered~~maintain ~~into~~at ~~forward~~all ~~swaps~~times ~~with~~either ~~members~~availability of(borrowing ~~our~~base ~~bank~~less ~~group~~amounts ~~to manage~~borrowed ~~our~~and ~~exposure~~letters toof ~~market~~credit ~~risk~~issued) ~~for~~of ~~our protected-price customers rather than purchase futures contracts~~$43.5 ~~These~~million ~~institutions~~(15% ~~have~~of ~~not~~the ~~required~~maximum anfacility ~~initial~~size) ~~cash margin deposit~~ or ~~any mark to market maintenance margin for these swaps. Any mark to market exposure is reserved against our borrowing base. As~~ a ~~result~~fixed ofcharge ~~this~~coverage ~~strategy, the cost to finance our protected-price program will be reduced.~~ ratio

~~Included~~41 in our accounts receivable is $20.6 million related to the sale of heating and air-conditioning equipment that is payable on a short-term installment basis. In July 2006, we entered into a preferred arrangement with a financial institution that finances installations for our customers. Over time, we anticipate that these short-term installation receivables will be reduced and both liquidity and availability will be increased.

Prior to October 18, 2004, we were generally able to obtain trade credit from home heating oil suppliers. Since then we have been required to prepay for most of our heating oil supply. However, as a result of the recapitalization, we have received some form of trade credit from several of our suppliers and we plan to issue letters of credit rather than prepay with cash for inventory purchases.

For the majority of our fiscal year, the amount of cash received from customers with a budget payment plan is greater than actual billings. This amount is reflected on the balance sheet under the caption “customer credit balances.” At September 30, 2006, customer credit balances aggregated $73.9 million. Generally, customer credit balances are at their low point after the end of the heating season and peak prior to the beginning of the heating season. At September 30, 2005, customer credit balances were $65.3 million. During the non-heating season, cash is provided from customer credit balances to fund operating activities.

Before October 2007, we must implement certain changes to ensure compliance with amended Environmental Protection Agency regulations. We currently estimate that the capital required to effectuate these requirements will range from $1.0 to $1.5 million. Annual maintenance capital expenditures are estimated to be approximately $4 to $6 million, excluding the capital requirements for environmental compliance. We have $174.2 million of long-term debt outstanding as of September 30, 2006, which includes $174.1 million of 10 1/4% senior notes due 2013.

As (as ~~mentioned~~defined in ~~Item~~ the credit agreement) of not less than 1.1x. -As ~~Business~~of ~~Initiatives~~September 30, 2009, availability, as defined in the amended and ~~Strategy~~restated credit agreement, wewas ~~plan~~$194.4 tomillion ~~seek~~and the Partnership was in compliance with the fixed charge coverage ratio. The fixed charge coverage ratio is calculated based upon Adjusted EBITDA. In the event that the Partnership is not able to ~~acquire~~comply ~~other~~with these covenants it could have a material ~~heating~~adverse ~~oil~~effect ~~distributors.~~on ~~Currently~~the wePartnership’s ~~are~~liquidity ~~reviewing~~and ~~several~~results ~~acquisition~~of ~~candidates~~its operations.

The Partnership’s scheduled interest payments for fiscal 2010 are $13.6 million and annual maintenance capital expenditures for fixed assets are estimated to be approximately $3.0 to $5.0 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 be required to make minimum cash contributions to fund its frozen defined benefit pension obligations of approximately $13.2 million in fiscal 2010 and $14.4 million in total for the four years subsequent to fiscal 2010. We anticipate paying distributions of approximately $19.5 million in fiscal 2010 and for the remainder of fiscal 2010, we will continue to purchase the remaining balance (3.4 million units) authorized under our unit repurchase plan. The Partnership also is contemplating calling a portion on our 10.25% senior notes in February 2010. In addition, we will continue to seek strategic acquisitions.

Partnership Distribution Provisions

~~There~~Commencing ~~will~~with bethe nofiscal ~~mandatory~~quarter ~~distributions~~ended ofDecember 31, ~~available~~2008, ~~cash~~we byare usrequired 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 ~~common~~Partnership ~~units~~Agreement, ~~and~~generally ~~general~~means ~~partner~~all ~~units~~cash ~~through~~on hand at the end of the relevant fiscal quarter less the amount of cash reserves established by the ~~ending~~Board ~~September 30,~~of ~~2008.~~Directors ~~(See~~of ~~Part~~our IIgeneral -partner ~~Item~~in 5its reasonable discretion for future cash requirements. ~~Market~~These reserves are established for ~~Registrant’s~~the ~~Units~~proper conduct of our business, including acquisitions, the payment of debt principal and ~~Related~~interest ~~Matters~~and -for distributions ~~Partnership~~during ~~Distribution~~the ~~Provisions~~next four quarters and ~~Note~~to 6comply with applicable laws and the terms of any debt agreements or other agreements to which we are subject. ~~Quarterly~~Under ~~Distribution~~the terms of our credit facility, the Partnership must have 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 the Partnership to have a fixed charge coverage ratio of 1.25x. These tests restrict the amount of cash that the Partnership 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 October 21, 2009, we declared a quarterly distribution of $0.0675 per unit, or $0.27 on an annualized basis, on all common units and general partner units in respect of the fourth quarter of fiscal 2009 payable on November 13, 2009 to holders of record on November 5, 2009. The total quarterly distribution is $4.9 million.

(See Part II—Item 5. Market for Registrant’s Units and Related Matters—Partnership Distribution Provisions and Note 5 Quarterly Distribution of Available Cash)

Contractual Obligations and Off-Balance Sheet Arrangements

We have no special purpose entities or off balance sheet debt, other than operating leases entered into in the ordinary course of business.

Long-term contractual obligations, except for our long-term debt obligations, are not recorded in our consolidated balance sheet. Non-cancelable purchase obligations are obligations we incur during the normal course of business, based on projected needs.

~~The~~Reserves for income taxes under FASB ASC 740-10-05 Income Taxes Topic (“FIN 48”) are not included in the table ~~below~~because ~~summarizes~~we cannot reasonably predict the ~~payment~~ultimate ~~schedule~~timing of settlement of our ~~contractual~~reserves ~~obligations~~for ~~at September 30,~~income ~~2006~~taxes ~~(in~~with ~~thousands):~~the respective taxing authorities.

	Payments Due by Year
	Total		1 Year		2 - 3 Years		4 - 5 Years		More Than 5 Years
Long-term debt obligations (a)	$	174,056	$	—	$	—	$	—	$	174,056
Capital lease obligations (b)		743		173		470		100		—
Operating lease obligations (c)		55,794		8,772		14,873		9,954		22,195
Purchase obligations (d)		128,980		25,970		39,856		36,515		26,639
Interest obligations Senior Notes (e)		115,095		17,707		35,414		35,414		26,560
Long-term liabilities reflected on the balance sheet (f)		5,900		395		790		165		4,550
	$	480,568	$	53,017	$	91,403	$	82,148	$	254,000

(a) Excludes current maturities of long-term debt of $0.1 million, which are classified within current liabilities.

(b) Represents various third party capital leases for trucks.

(d) Represents non-cancelable commitments as of September 30, 2006, including amounts due under employment agreements.

(e) Reflects 10 1/4% interest obligations on our $174.1 million senior notes due February 2013.

(f) Reflects long-term liabilities excluding a pension accrual of approximately $21.2 million. Under current prescribed regulatory minimum funding requirements, we have satisfied the minimum funding obligations related to our pension plans for fiscal 2006 and 2007. The remaining long-term liabilities reflected on the balance sheet represent the present value of amounts due subsequent to September 30, 2006 per the separation agreement entered into with the former CEO in March 2005. At September 30, 2006, approximately $5.9 million is scheduled to be paid out to the former CEO over the term of the separation agreement as follows: (i) $395,000 per year for five years following the termination date in March 2005, and (ii) $350,000 per year for 13 years beginning with the month following the five-year anniversary of the termination date. The payments scheduled by year in the tabular presentation above, totaling $5.9 million, represents undiscounted payments and are therefore greater than the present value of these payments totaling $3.9 million at September 30, 2006, which is part of the other long-term liabilities amount on the Balance Sheet.

Recent Accounting Pronouncements

In July 2006, the Financial Accounting Standards Board (“FASB”) issued Financial Interpretation No. 48 “Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109.” In September 2006, the FASB issued Statement No. 157 “Fair Value Measurements” and Statement No. 158 “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans.” And in September 2006, the Securities and Exchange Commission (“SEC”) issued Staff Accounting Bulletin (“SAB”) No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements.” (See Note 4. Summary of Significant Accounting Policies – Recent Accounting Pronouncements)

The table below summarizes the payment schedule of our contractual obligations at September 30, 2009 (in thousands):


	Payments Due by Fiscal Year
	Total		2010		2011 and 2012		2013 and 2014		Thereafter
Long-term debt obligations	$	133,112	$	—	$	—	$	133,112	$	—
Capital lease obligations (a)		53		53				—		—
Operating lease obligations (b)		50,522		8,965		15,236		12,364		13,957
Purchase obligations (c)		15,659		7,177		8,462		20		—
Interest obligations (d)		51,659		15,081		29,787		6,791		—
Long-term liabilities reflected on the balance sheet (e)		4,773		369		700		700		3,004

	$	255,778	$	31,645	$	54,185	$	152,987	$	16,961

(a)	Represents various third party capital leases for trucks.

(b)	Represents various operating leases for office space, trucks, vans and other equipment with third parties.

(c)	Represents non-cancelable commitments as of September 30, 2009 for operations such as customer related stationary and voice and data phone/computer services.

(d)	Reflects 10.25% interest obligations on our $133.1 million senior notes due February 2013 and the unused commitment fee on the revolving credit facility.

(e)

Reflects long-term liabilities excluding a pension accrual of approximately $24.7 million. Under current prescribed regulatory minimum funding requirements, we have satisfied the minimum funding obligations related to our pension plans for fiscal 2009 and we estimate minimum cash contributions of $13.2 million, $4.3 million, $3.6 million, $3.3 million and $3.2 million, for fiscal 2010, 2011, 2012, 2013 and 2014 respectively.

Recent Accounting Pronouncements

In the first quarter of fiscal 2009, the Partnership adopted the provisions of FASB ASC 820-10 Fair Value Measurements and Disclosure topic (SFAS No. 157), which defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements.

In the second quarter of fiscal 2009, the Partnership adopted the provisions of FASB ASC 815-10-50 Derivatives and Hedging topic, Disclosure subtopic (SFAS No. 161) which amends and expands the disclosure requirements of FASB ASC 815-10-05 Derivatives and Hedging topic (SFAS No. 133). This standard also established qualitative disclosures about objectives and strategies for using derivatives, quantitative disclosures about fair value amounts of gains and losses on derivative instruments, and disclosures about credit-risk-related contingent features in derivative agreements.

In the third quarter of fiscal 2009, the Partnership adopted the provisions of FASB ASC 855-10 Subsequent Events topic (SFAS No. 165). This standard established disclosures, principles and requirements for events that occur after the balance sheet date but before financial statements are issued.

In December 2007, the FASB issued a revision to FASB ASC 805-10 Business Combinations (SFAS No. 141R). This standard establishes in a business combination principles and requirements for how an acquirer recognizes and measures identifiable assets acquired, goodwill acquired, liabilities assumed, and any noncontrolling interests. It is effective in fiscal years beginning after December 15, 2008. The Partnership is required to adopt this standard in fiscal 2010. The Partnership is currently assessing its impact.

Critical Accounting Estimates

The preparation of financial statements in conformity with Generally Accepted Accounting Principles requires management to establish accounting policies and make estimates and assumptions that affect reported amounts of assets and liabilities at the date of the Consolidated Financial Statements. Star Gas evaluates its policies and estimates on an on-going basis. The Partnership’s Consolidated Financial Statements may differ based upon different estimates and assumptions. The Partnership’s critical accounting estimates have been reviewed with the Audit Committee of the Board of Directors.

~~Our~~43 ~~significant accounting policies are discussed in Note 3 to the Consolidated Financial Statements. We believe the following are our critical accounting policies and estimates:~~

Our significant accounting policies are discussed in Note 3. to the Consolidated Financial Statements. We believe the following are our critical accounting policies and estimates:

Goodwill and Other Intangible Assets

We calculate amortization using the straight-line method over periods ranging from five to ten years for intangible assets with definite useful lives based on historical statistics. We use amortization methods and determine asset values based on our best estimates using reasonable and supportable assumptions and projections. From time to time, we engage a third party valuation firm to ascertain asset values for intangible assets. We assess the useful lives of intangible assets based on the estimated period over which we will receive benefit from such intangible assets such as historical evidence regarding customer churn rate. In some cases, the estimated useful lives are based on contractual terms. At September 30, ~~2006~~2009, we had $6120.5 million of net intangible assets subject to amortization. If circumstances required a change in estimated useful lives of the assets, it could have a material effect on results of operations. For example, if lives were shortened by one year, we estimate that amortization for these assets for fiscal ~~2006~~2009 would have increased by approximately $20.69 million.

FASB ASC 350-10-05 Intangibles-Goodwill and Other topic (SFAS No. 142) requires goodwill to be assessed at least annually for impairment. These assessments involve management’s estimates of future cash flows, market trends and other factors to determine the fair value of the reporting unit, which includes the goodwill to be assessed. If the carrying amount of goodwill exceeds its implied fair value and is determined to be impaired, an impairment charge is recorded to write-down goodwill to its fair value. At September 30, ~~2006~~2009, we had $~~166~~182.59 million of goodwill. Intangible assets with finite lives must be assessed for impairment whenever changes in circumstances indicate that the assets may be impaired. Similar to goodwill, the assessment for impairment requires estimates of future cash flows related to the intangible asset. To the extent the carrying value of the assets exceeds its future undiscounted cash flows, an impairment loss is recorded based on the fair value of the asset. We test the carrying amount of goodwill annually during the fourth fiscal quarter. During the second quarter of fiscal 2005, a number of events occurred that indicated a possible impairment of goodwill. These events included: the determination in February 2005 that we could expect to generate significantly lower than expected operating results for the year and a significant decline in the Partnership’s unit price. As a result of these triggering events and circumstances, we completed an interim SFAS No. 142 impairment review with the assistance of a third party valuation firm as of February 28, 2005. The evaluation utilized both an income and market valuation approach and contained reasonable assumptions and reflected management’s best estimate of projected future cash flows. This review resulted in a non-cash goodwill impairment charge of approximately $67 million, which reduced the carrying amount of goodwill. As of August 31, 2006, we performed our annual goodwill impairment valuation. Based upon this analysis, we determined that there is no additional goodwill impairment as of August 31, 2006.

~~Depreciation~~We test the carrying amount of ~~Property~~goodwill annually during the fourth fiscal quarter. It was determined based on this analysis that there was no goodwill impairment as of August 31, ~~Plant~~2009. The preparation of this analysis was based upon management’s estimates and ~~Equipment~~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.

~~Depreciation~~Although ~~is calculated using~~ the ~~straight-line~~Partnership ~~method~~believes ~~based~~that onits ~~the~~projections ~~estimated~~reflect ~~useful~~its ~~lives~~best estimates of ~~the~~future ~~assets~~performance, ~~ranging~~changes in ~~from~~estimated 1revenues, toper 40gallon ~~years.~~margins ~~Net~~or ~~property,~~discount ~~plant~~rates ~~and~~may ~~equipment~~have ~~was~~an ~~$42.4~~impact ~~million~~on atthe ~~September 30,~~estimated ~~2006~~fair value. IfAny ~~circumstances required~~increase ~~a change~~ in estimated ~~useful~~cash ~~lives~~flows ofor a decrease in the ~~assets,~~discount itrate ~~could~~would not have aan ~~material~~impact ~~effect~~ on ~~results~~the carrying value of ~~operations~~the goodwill. ~~For~~A decrease ~~example,~~in iffuture ~~the~~estimated ~~remaining~~cash ~~estimated~~flows ~~useful~~or ~~lives~~an ofincrease ~~these~~in ~~assets~~the ~~were~~discount ~~shortened~~rate bycould ~~one~~require ~~year,~~the wePartnership ~~estimate~~to ~~that~~determine ~~depreciation~~whether ~~for fiscal~~the ~~2006~~recognition ~~would~~of ~~have~~a ~~increased~~goodwill byimpairment ~~approximately~~charge ~~$3.6~~would ~~million~~be required.

~~Fair~~The ~~Values~~Partnership Ofestimates ~~Derivatives~~the fair value of its sole reporting unit utilizing two generally accepted approaches: the Income Approach and the Market Approach (which is a combination of the Market Comparable and the Market Transaction Approaches).

The ~~fair~~Income ~~market~~Approach uses ~~value~~management’s projections of ~~all~~cash ~~derivative~~flows, ~~instruments~~market istrends ~~recognized~~and asother anfactors ~~asset~~to ordetermine ~~liability~~the value of the reporting unit based on ~~our~~discounted ~~balance~~cash ~~sheet~~flows. ToThe ~~the~~Partnership’s ~~extent~~discount ~~that~~rate ~~any~~was ~~derivative instrument~~calculated ~~does~~based ~~not~~on ~~meet~~ the ~~requirements~~weighted average cost of capital, ~~SFAS~~using ~~133~~inputs toof ~~qualify~~comparable ~~for~~companies ~~hedge~~in ~~accounting,~~the ~~changes~~same inindustry. The Partnership’s conclusion of the fair value of ~~that~~the ~~derivate~~reporting ~~instrument~~unit iswas ~~recognized~~supported ~~currently~~based inon ~~earnings.~~a ~~The~~sensitivity ~~Partnership~~analysis isperformed ~~currently~~using ~~evaluating~~a ~~whether~~range toof ~~elect~~discount ~~hedge accounting~~rates ~~for~~and ~~future periods~~terminal multiples.

33The Market Comparable Approach determines a fair value of the reporting unit based on comparable companies in similar industries, whose securities are actively traded in public markets. A financial multiple range was calculated and applied to the financial metrics of the Partnership. The Partnership’s conclusion was supported using the high and low range of multiples applied.

The Market Transaction Approach determines a fair value of the reporting unit based on exchange prices in actual sales and purchases of comparable businesses. A transaction multiple was calculated and applied to the financial metrics of the Partnership. In addition, a transaction occurring after the analysis date, but before the fiscal year-end was reviewed, and the Partnership’s conclusion of value was supported based on the calculations of these transaction multiples.

~~The~~In ~~estimated~~addition, ~~fair~~the ~~value~~Partnership ofperforms ~~our~~a ~~derivative~~reasonableness ~~instruments~~check ~~requires~~of ~~judgment~~its onconcluded ~~our~~value ~~part.~~for ~~We have established~~its ~~the~~sole ~~fair~~reporting ~~value~~unit ~~of our derivative instruments using estimates determined~~ by ~~our~~reconciling ~~counterparties~~the and subsequently evaluated them internally using established index prices and other sources. These values are based upon, among other things, future prices, volatility, time-to-maturity value and credit risk. The values we report in our financial statements change as these estimates are revised to reflect actual results, ~~changes in market conditions, or other factors, many~~ of ~~which~~the ~~are~~goodwill ~~beyond our~~analysis ~~control.~~with ~~The~~its ~~factors underlying our estimates of fair value are impacted by actual results and changes in conditions,~~ market ~~and otherwise, which may be beyond our control~~capitalization.

Depreciation of Property, Plant and Equipment

Depreciation is calculated using the straight-line method based on the estimated useful lives of the assets ranging from 1 to 40 years. Net property, plant and equipment was $37.5 million at September 30, 2009. If circumstances required a change in estimated useful lives of the assets, it could have a material effect on results of operations. For example, if the remaining estimated useful lives of these assets were shortened by one year, we estimate that depreciation for fiscal 2009 would have increased by approximately $1.2 million.

Fair Values of Derivatives

FASB ASC 815-10-05 Derivatives and Hedging topic (SFAS No. 133), 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 and FASB ASC 815-10-05 Derivatives and Hedging topic documentation requirements have been met, changes in fair value are recognized in other comprehensive income until the underlying hedged item is recognized in earnings. Currently, 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 are recognized in our statement of operations.

We have established the fair value of our derivative instruments using estimates determined by our counterparties and subsequently evaluated them internally using established index prices and other sources. These values are based upon, among other things, future prices, volatility, time-to-maturity value and credit risk. The estimate of fair value we report in our financial statements change as these estimates are revised to reflect actual results, changes in market conditions, or other factors, many of which are beyond our control.

Defined Benefit Obligations

~~SFAS~~FASB ~~No. 87,~~ASC ~~“Employers’~~715-10-05 ~~Accounting~~Compensation-Retirement ~~for~~Benefits ~~Pensions”~~topic, ~~as amended~~requires byan ~~SFAS~~employer ~~No.~~to (i) ~~132~~measure ~~“Employers~~the ~~Disclosure~~funded ~~about~~status ~~Pensions~~of ~~and~~a ~~Other~~defined ~~Postretirement~~benefit ~~Benefits”~~postretirement ~~requires~~plan as of the ~~Partnership~~date toof ~~make~~its ~~assumptions~~fiscal asyear-end statement of financial position, (ii) to recognize the ~~expected~~overfunded ~~long-term~~or ~~rate~~underfunded status of ~~return~~this ~~that~~plan ~~could~~as bean ~~achieved~~asset onor ~~defined~~liability ~~benefit~~in ~~plan assets~~its ~~and~~statement ~~discount~~of ~~rates~~financial toposition ~~determine~~and ~~the~~(iii) to ~~present~~recognize ~~value~~changes ofin ~~the~~that ~~plans’~~funded ~~pension~~status ~~obligations.~~in ~~The~~the ~~Partnership~~year ~~evaluates~~which ~~these~~the ~~critical~~changes ~~assumptions~~occur atthrough comprehensive ~~least annually~~income.

~~The~~This ~~discount~~standard ~~rate~~requires ~~enables~~ the Partnership to ~~state~~make ~~expected~~assumptions ~~future~~as ~~cash flows at a present value on the measurement date. The rate is required~~ to ~~represent~~ the ~~market~~expected ~~rate for high~~long-~~quality~~term ~~fixed~~rate ~~income~~of ~~investments. A~~return ~~lower~~that ~~discount~~could ~~rate~~be ~~increases~~achieved ~~the~~on ~~present~~defined ~~value of~~ benefit ~~obligations~~plan ~~and~~assets ~~increases pension expense. A 25 basis point decrease in the discount rated used for fiscal 2006 would have increased pension expense by approximately $0.1 million~~ and ~~would have increased the minimum pension liability by another $1.7 million. The~~ discount ~~rate~~rates ~~used~~ to determine ~~net~~the ~~periodic~~present ~~pension~~value ~~expense was 5.5% in 2006 and 6.0% in 2005 and 2004. The discount rate used in determining end~~ of ~~year~~the plans’ pension obligations ~~was 5~~.~~75%~~ inThe ~~2006,~~Partnership ~~5.5%~~evaluates inthese ~~2005~~critical ~~and~~assumptions ~~6.0%~~at inleast ~~2004~~annually. These rates reflect the yield of high quality (AA or better rating by a recognized rating agency) corporate bonds whose cash flows are expected to match the timing and amounts of future benefit payments.

WeThe ~~consider~~discount rate enables the ~~current~~Partnership ~~and~~to state expected ~~asset~~future ~~allocations,~~cash asflows ~~well~~at asa ~~historical~~present ~~and~~value ~~expected~~on ~~returns~~the onmeasurement ~~various~~date. ~~categories~~The ofrate ~~plan~~is ~~assets~~required to ~~determine~~represent ~~our~~the ~~expected~~market ~~long~~rate for high-~~term~~quality fixed income investments. A lower discount rate increases the present value of ~~return~~benefit onobligations and increases pension ~~plan~~expense ~~assets~~in the following fiscal year. ~~The~~A ~~expected~~25 ~~long-term~~basis ~~rate~~point ofdecrease ~~return~~in onthe discount ~~assets~~rated isused ~~developed~~for ~~with~~fiscal ~~input~~2009 ~~from~~would ~~the~~have ~~Partnership’s~~increased ~~qualified~~pension ~~actuaries~~expense by approximately $0.1 ~~The~~million ~~long-term~~and ~~rate~~would ofhave ~~return~~increased ~~assumption~~the pension liability by another $1.3 million. The discount rate used ~~for~~ ~~determining~~to determine net periodic pension expense ~~for~~was ~~fiscals~~7.6% in ~~2006~~2009, 6.2% in 2008, and ~~2005~~5.75% in 2007. The discount rate used in determining end of year pension obligations was 85.254%. Ain ~~further~~2009, 257.6% ~~basis~~in ~~point~~2008, ~~decrease~~and 6.2% in ~~the~~2007. ~~expected~~These ~~return~~rates onreflect ~~assets~~the ~~would~~yield ~~have~~of ~~increased~~high ~~pension~~quality ~~expense~~(AA inor ~~fiscal~~better ~~2006~~rating by ~~approximately~~a ~~$0.1~~recognized rating ~~million~~agency) corporate bonds whose cash flows are expected to match the timing and amounts of future benefit payments.

~~Over~~We consider the ~~life~~current ofand ~~the~~expected ~~plans~~asset allocations, ~~both~~as ~~gains~~well as historical and ~~losses~~expected ~~have~~returns ~~been~~on ~~recognized~~various bycategories ~~the~~of ~~plans~~plan inassets ~~the~~to ~~calculation~~determine our expected long-term rate of ~~annual~~return on pension ~~expense~~plan assets. AsThe expected long-term rate of return on ~~September 30,~~assets ~~2006,~~is ~~$21~~developed with input from the Partnership’s qualified actuaries.2 ~~million~~The long-term rate of ~~unrecognized~~return ~~losses~~assumption ~~remain~~used tofor bedetermining ~~recognized~~net byperiodic ~~the~~pension ~~plans~~expense for fiscal 2009 and 2008 was 8.25%. ~~These~~A ~~losses~~further ~~may~~25 ~~result~~basis inpoint ~~increases~~decrease in ~~future~~the expected return on assets would have increased pension expense asin ~~they~~fiscal ~~are~~2009 ~~recognized~~by approximately $0.1 million.

Over the life of the plans, both gains and losses have been recognized by the plans in the calculation of annual pension expense. As of September 30, 2009, $31.2 million of unrecognized losses remain to be recognized by the plans. These losses may result in increases in future pension expense as they are recognized.

Recent market conditions have resulted in an unusually high degree of volatility and increased the risks associated with certain investments held by the plans that could impact the value of investments after the date of these financial statements.

In addition, we participate in a number of trustee-managed multi-employer pension and health and welfare plans for employees covered under collective bargaining agreements. The Partnership makes timely contributions as required by the plans. Several factors could result in potentially higher future contributions to these plans, including unfavorable investment performance, changes in demographics, and increased benefits to participants.

Allowance for Doubtful Accounts

We periodically review past due customer accounts receivable balances. After giving consideration to economic conditions, overdue status and other factors, ~~the~~we ~~heating~~establish ~~oil segment establishes~~ an allowance for doubtful accounts, ~~which~~representing itthe ~~deems~~Partnership’s ~~sufficient~~best toestimate ~~cover~~of ~~future~~amounts ~~potential~~that ~~losses~~may not be collectible. Actual losses could differ from management’s estimates~~; however, based on historical experience, we do not expect our estimate of uncollectible accounts to vary significantly from actual losses~~.

Insurance Reserves

We currently self-insure a portion of workers’ compensation, auto and general liability claims. We establish reserves based upon expectations as to what our ultimate liability may be for outstanding claims using developmental factors based upon historical claim experience, supplemented by a third-party actuary. We periodically evaluate the potential for changes in loss estimates with the support of qualified actuaries. As of September 30, ~~2006~~2009, we had approximately $3834.8 million of insurance reserves. The ultimate resolution of these claims could differ materially from the assumptions used to calculate the reserves, which could have a material adverse effect on results of operations.

ITEM 7A.

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. ~~During fiscal 2006, our average working capital borrowing was $9.7 million and the maximum borrowed was $47 million in January 2006.~~

At September 30, ~~2006~~2009, we had outstanding borrowings totaling $ ~~174~~133.2 1 million, none of which is subject to variable interest rates.

We ~~also~~regularly ~~selectively~~ 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 September 30, ~~2006~~2009, the potential impact on our hedging activity would be to increase the fair market value of these outstanding derivatives by $7.02 million to a fair market value of $(221.6) million; and conversely a hypothetical ten percent decrease in the cost of product would decrease the fair market value of these outstanding derivatives by $74.27 million to a fair market value of $~~(16~~9.8)7 million.

ITEM 8.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The financial statements and financial statement schedules referred to in the index contained on page F-1 of this report are incorporated herein by reference.

ITEM 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

NONE

ITEM 9A.

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 September 30, 2009. Based on that evaluation, such principal executive officer and principal financial officer concluded that the Partnership’s disclosure controls and procedures were effective as of September 30, ~~2006~~2009 at the reasonable level of assurance. For purposes of Rule 13a-15(e), the term disclosure controls and procedures means controls and other procedures of an issuer that are designed to ensure that ~~the~~ information required to be disclosed by the ~~Partnership~~issuer in the reports ~~filed~~that it files or submits under the ~~Securities~~Act ~~Exchange~~(15 ~~Act~~U.S.C. of78a ~~1934~~et seq.) is recorded, processed, summarized and reported, within the time periods specified in the ~~SEC~~Commission’s rules and forms. ~~Based~~Disclosure oncontrols ~~that~~and ~~evaluation~~procedures include, ~~such~~without ~~principal~~limitation, ~~executive~~controls ~~officer~~ and procedures ~~principal~~designed ~~financial~~to ~~officer~~ensure ~~concluded~~ that information required to be disclosed by an issuer in the ~~Partnership’s~~reports ~~disclosure~~that ~~controls~~it ~~and~~files ~~procedures~~or assubmits ofunder ~~September~~the ~~30, 2006~~Act ~~were~~is ~~not~~accumulated ~~effective~~and ~~because~~communicated ofto the ~~material~~issuer’s ~~weakness~~management, inincluding ~~internal~~its ~~control~~principal ~~over~~executive and principal financial ~~reporting~~officer, inor ~~hedge~~persons ~~accounting~~performing similar functions, as ~~discussed~~appropriate ~~below~~to allow timely decisions regarding required disclosure.

~~(b)~~46 ~~Management’s Report on Internal Control over Financial Reporting.~~

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) under the Securities Exchange Act of 1934, as amended. Under the supervision of management and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation of internal control over financial reporting, the Partnership identified the following material weakness with regard to its accounting for certain derivative instruments in accordance with Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS 133):

The Partnership did not have personnel with sufficient technical expertise related to the application of the provisions of SFAS 133. Specifically, the Partnership’s personnel lacked sufficient technical expertise to ensure compliance with the documentation requirements of SFAS 133 at inception of certain hedge relationships. This material weakness resulted in the restatement of the Partnership’s consolidated financial statements for fiscal years ended September 30, 2005 and 2004, the first, second and third quarters of fiscal 2006 and each of the quarters in fiscal 2005.

As a result of the material weakness described above, management concluded that the Partnership’s internal control over financial reporting was not effective as of September 30, 2006.

Our management’s assessment of the effectiveness of our internal control over financial reporting as of September 30, 2006 has been audited by KPMG LLP, an independent registered public accounting firm, as stated in their report which is included herein.

(b) Management’s Report on Internal Control over Financial Reporting.

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) under the Securities Exchange Act of 1934, as amended. Under the supervision of management and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation of internal Control over financial reporting, our management concluded that our internal control over financial reporting was effective as of September 30, 2009. The effectiveness of our internal control over financial reporting as of September 30, 2009 has been audited by our independent registered public accounting firm, as stated in their report which is included herein.

No change in the Partnership’s internal control over financial reporting occurred during the Partnership’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect the Partnership’s internal control over financial reporting.

(d) Other.

The ~~Partnership~~General ~~restated~~Partner ~~its financial~~and ~~statements~~the ~~for~~Partnership ~~fiscal~~believe ~~years~~that ~~ended~~a ~~September~~control 30system, ~~2005~~no ~~and~~matter ~~2004~~how ~~and~~well ~~the~~designed ~~first, second~~ and ~~third~~operated, ~~quarters~~can ofnot ~~fiscal~~provide ~~2006~~absolute ~~and~~assurance ~~each~~that of the ~~quarters~~objectives inof ~~fiscal 2005 because it did not comply with~~ the ~~initial~~control ~~documentation~~system ~~requirements~~are ofmet, and ~~paragraph~~no ~~28(a)(2)~~evaluation of ~~SFAS~~controls ~~133~~can ~~which~~provide ~~states~~absolute assurance that aall ~~forecasted~~control ~~transaction~~issues ~~shall~~and beinstances ~~described~~of ~~with~~fraud, ~~sufficient~~if ~~specificity~~any, ~~such~~within ~~that~~the ~~when~~Partnership ahave ~~specific~~been ~~transaction~~detected. ~~occurs~~Therefore, ita iscontrol ~~clear~~system, ~~whether~~no ~~the~~matter ~~specific~~how ~~transaction~~well isconceived orand isoperated, ~~not~~can ~~the~~provide ~~hedged transaction.~~only ~~The~~reasonable, ~~Partnership’s~~not ~~initial~~absolute, ~~documentation~~assurance ~~lacked~~that ~~this~~the ~~clarity~~objectives asof the ~~hedging~~control ~~instruments~~system ~~for~~are amet. ~~given~~Our ~~month~~disclosure ~~could~~controls ~~not~~and beprocedures ~~linked~~are designed to aprovide ~~specific~~such ~~purchase~~reasonable ~~during~~assurances ~~the~~of ~~month.~~achieving Inour ~~addition~~desired tocontrol ~~not~~objectives, ~~meeting~~and the ~~documentation~~principal ~~requirements, the Partnership has~~executive ~~also~~officer ~~determined~~and ~~that~~principal ~~its~~financial ~~forward~~officer ~~contracts~~of ~~did~~our ~~not~~general ~~meet~~partner ~~the~~have ~~criteria~~concluded, as ~~described in paragraph 65(a)~~ of ~~SFAS~~September 30, ~~133~~2009, ~~which permits an entity to assume~~ that aour ~~hedge~~disclosure ofcontrols aand ~~forecasted~~procedures ~~purchase~~were ofeffective ain ~~commodity~~achieving ~~with a forward contract will be highly effective and~~ that ~~there~~level ~~will~~of bereasonable ~~no ineffectiveness to be recognized~~assurance.

The Partnership believes that its initial accounting treatment of certain derivative transactions properly reflected the intent and economics of the underlying transactions; however, the interpretations of how to apply SFAS 133 and how to adequately provide documentation for such instruments so as to qualify for hedge accounting are complex and continue to evolve. Since the initial documentation did not meet the requirements of SFAS 133 to allow certain derivative instruments to qualify for hedge accounting, any changes in the market value of these derivative instruments prior to their maturity are recorded through the Consolidated Statements of Operations rather than through Consolidated Statements of Comprehensive Income. There is no effect on consolidated cash flows, or Total Partners’ Capital.

The General Partner and the Partnership believe that a control system, no matter how well designed and operated, can not provide absolute assurance that the objectives of the control system are met, and no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the Partnership have been determined.

(e) Remediation

The Partnership is evaluating the accounting technical expertise requirements necessary for compliance with SFAS 133 and considering whether it will choose to apply hedge accounting in the future. Prior to applying hedge accounting in future periods, the Partnership will ensure that it has appropriate resources with sufficient technical expertise to comply with the provisions of SFAS 133 to qualify for hedge accounting.

ITEM 9B.

OTHER INFORMATION

Not ~~Applicable~~applicable.

PART III

ITEM 10. DIRECTORS, ~~AND~~ EXECUTIVE OFFICERS OFAND ~~THE~~CORPORATE ~~REGISTRANT~~GOVERNANCE

Partnership Management

~~Effective~~The ~~as of April 28, 2006, Star Gas LLC withdrew as the~~ general partner of the Partnership ~~and~~is Kestrel Heat, ~~became~~LLC. ~~the~~The ~~general~~Board ~~partner~~ of ~~the~~Directors ~~Partnership, in accordance with the terms~~ of ~~the unit purchase agreement.~~ Kestrel Heat, LLC is ~~wholly-owned~~appointed by ~~Kestrel.~~its ~~Kestrel~~sole ~~appoints~~member, ~~all~~Kestrel ofEnergy ~~the~~Partners, ~~directors~~LLC. of Kestrel ~~Heat.~~Energy ~~Kestrel~~Partners, LLC is a private equity investment partnership formed by Yorktown Energy Partners VI, L.P. ~~(“Yorktown”)~~, Paul A. Vermylen and other investors.

~~Kestrel~~The ~~Heat,~~Partnership’s asoperations ~~the~~are ~~general~~conducted ~~partner~~through ofPetro ~~the Partnership~~Holdings, ~~oversees~~Inc. and ~~the~~its ~~activities of the Partnership~~subsidiaries. ~~Unitholders~~Petro doHoldings, ~~not directly or indirectly participate in the management or operation of the Partnership or elect the directors of the general partner~~Inc. ~~The~~is ~~Board~~a ofcorporation ~~Directors~~that ofis ~~the general partner has adopted~~ a ~~set~~wholly-owned ofsubsidiary ~~Partnership Governance Guidelines in accordance with the requirements~~ of ~~the~~Star ~~New~~Acquisitions, ~~York~~which ~~Stock~~is ~~Exchange.~~a Awholly-owned ~~copy~~subsidiary of ~~these Guidelines is available on~~ the ~~Partnership’s~~ ~~website at www~~Partnership.~~Star-Gas.com~~ ~~or a copy may be obtained without charge by contacting Richard F. Ambury, (203) 328-7300.~~

AsKestrel Heat, LLC as the general partner of ~~December 14,~~the ~~2006~~Partnership, ~~Kestrel~~oversees ~~Heat~~the ~~and~~activities ~~its~~of ~~affiliates~~the ~~owned~~Partnership. anUnitholders ~~aggregate~~do ofnot ~~12,803,128~~directly ~~common~~or ~~units,~~indirectly ~~representing~~participate ~~16.9%~~in the management or operation of the Partnership ~~issued~~or ~~and~~elect ~~outstanding~~the ~~common~~directors ~~units,~~of ~~and~~the ~~Kestrel~~general ~~Heat~~partner. ~~owned~~The ~~325,729~~Board of Directors of the general partner ~~units~~has adopted a set of Partnership Governance Guidelines in accordance with the requirements of the New York Stock Exchange. A copy of these Guidelines is available on the Partnership’s website at www.Star-Gas.com or a copy may be obtained without charge by contacting Richard F. Ambury, (203) 328-7310.

As of November 30, 2009, Kestrel Heat, LLC and its affiliates owned an aggregate of 12,803,128 common units, representing 17.85% of the issued and outstanding common units, and Kestrel Heat, LLC owned 325,729 general partner units.

The general partner owes a fiduciary duty to the unitholders. However, our partnership agreement contains provisions that allow the general partner to take into account the interests of parties other than the Limited Partners in resolving conflict of interest, thereby limiting such fiduciary duty. Notwithstanding any limitation on obligations or duties, the general partner will be liable, as the general partner of the Partnership, for all debts of the Partnership (to the extent not paid by the Partnership), except to the extent that indebtedness or other obligations incurred by the Partnership are made specifically non-recourse to the general partner.

As is commonly the case with publicly traded limited partnerships, the general partner does not directly employ any of the persons responsible for managing or operating the Partnership.

Directors and Executive Officers of the General Partner

Directors are ~~elected~~appointed for one-year terms. The following table shows certain information for directors and executive officers of the general partner as of ~~December~~ November 2930, ~~2006~~2009:

Name	Age	Position
Paul A. Vermylen, Jr.	6062	Chairman, Director
Joseph P. Cavanaugh	69	Chief Executive Officer and Director
Daniel P. Donovan	63	President, Chief Executive Officer and Director
Daniel P. Donovan	60	President, Chief Operating Officer and Director
Richard F. Ambury	52	Chief Financial Officer
Richard F. Ambury	49	Chief Financial Officer
Steven J. Goldman	49	Senior Vice President of Operations
Richard G. Oakley	4749	Vice President and Controller
Henry D. Babcock (1)	6669	Director
C. Scott Baxter (1)	4548	Director
Bryan H. Lawrence	6467	Director
Sheldon B. Lubar	7780	Director
William P. Nicoletti (1)	6164	Director

⁽¹⁾	Audit Committee member

Paul A. Vermylen, Jr. Mr. Vermylen has been the Chairman and a director of Kestrel Heat since April 28, 2006. Mr. Vermylen is a founder of Kestrel and has served as its President and as a manager since July, 2005. Mr. Vermylen ~~has~~ had been employed since 1971, serving in various capacities, including as a Vice President of Citibank N.A. and Vice President-Finance of Commonwealth Oil Refining Co. Inc. Mr. Vermylen served as Chief Financial Officer of Meenan Oil Co., L.P. from 1982 until 1992 and as President of Meenan Oil Co., L.P. until 2001, when Meenan was acquired by the Partnership. Since 2001, Mr. Vermylen has pursued private investment opportunities. Mr. Vermylen serves as a director of certain non-public companies in the energy industry in which Kestrel holds equity interests including Downeast LNG, Inc., ~~COALition Energy, LLC~~ and Moneta Energy Services Ltd. Mr. Vermylen is a graduate of Georgetown University and has a M.B.A. from Columbia University.

~~Joseph~~48 P. Cavanaugh. Mr. Cavanaugh has been Chief Executive Officer and a director of Kestrel Heat since April 28, 2006. Mr. Cavanaugh was Chief Executive Officer and a director of Star Gas from March 2005 until April 28, 2006. From December 2004, after the sale of the Partnership’s propane segment to Inergy L.P. to March 2005, Mr. Cavanaugh was employed by Inergy to direct the transition of the business to them. From March 1999 to December 2004 Mr. Cavanaugh was Chief Executive Officer of the Partnership’s propane segment. From December 1997 to March 1999, Mr. Cavanaugh served as President and Chief Executive Officer of Star Gas Corporation, a predecessor general partner. From October 1969 to December 1997, Mr. Cavanaugh held various financial and management positions with Petro. Mr. Cavanaugh is a graduate of Iona College and received an MS from Pace University.

Daniel P. Donovan. Mr. Donovan has been President and Chief Operating Officer and a director of Kestrel Heat since April 28, 2006. Mr. Donovan was President and Chief Operating Officer of Star Gas from May 2004 until April 28, 2006. From January 1980 to May 2004, he held various management positions with Meenan Oil Co. LP, including Vice President and General Manager from 1998 to 2004. Mr. Donovan worked for Mobil Oil Corp. from 1971 to 1980. His last position with Mobil was President and General Manager of its heating oil subsidiary in New York City and Long Island. Mr. Donovan is a graduate of St. Francis College in Brooklyn, New York and received an M.B.A. from Iona College.

Richard F. Ambury. Mr. Ambury has been Chief Financial Officer, Treasurer and Secretary of Kestrel Heat since April 28, 2006. Mr. Ambury was Chief Financial Officer, Treasurer and Secretary of Star Gas from May 2005 until April 28, 2006. From November 2001 to May 2005, Mr. Ambury was Vice President and Treasurer of Star Gas. From March 1999 to November 2001, Mr. Ambury was Vice President of Star Gas Propane, L.P. From February 1996 to March 1999,

Daniel P. Donovan. Mr. ~~Ambury~~Donovan ~~served~~has asbeen ~~Vice~~Chief ~~President—Finance~~Executive Officer of ~~Star~~Kestrel Heat ~~Gas~~since ~~Corporation~~May 31, 2007 and has been President and director since April 28, 2006. From April 28, 2006 to May 30, 2007 Mr. Donovan was also the ~~predecessor~~Chief ~~general~~Operating ~~partner~~Officer of Kestrel Heat. Mr. ~~Ambury~~Donovan was ~~employed~~President byand ~~Petro~~Chief Operating Officer of Star Gas from ~~June~~ ~~1983~~March ~~through~~2005 ~~February~~until ~~1996~~April 28, ~~where~~2006. From May 2004 to March 2005 he ~~served~~was inPresident ~~various~~and ~~accounting/finance~~Chief ~~capacities.~~Operating ~~From~~Officer ~~1979~~of tothe ~~1983,~~Star Gas heating oil segment. Mr. ~~Ambury~~Donovan ~~was~~held ~~employed~~various bymanagement apositions ~~predecessor~~with ~~firm~~Meenan ofOil Co. ~~KPMG~~LP, afrom ~~public~~January ~~accounting~~1980 ~~firm~~to May 2004, including Vice President and General Manager from 1998 to 2004. Mr. ~~Ambury~~Donovan ~~has~~worked ~~been~~for aMobil ~~Certified~~Oil ~~Public~~Corp. from 1971 to 1980. His last position with Mobil was President and General Manager of its heating oil ~~Accountant~~subsidiary ~~since~~in ~~1981~~New York City and Long Island. Mr. Donovan is a graduate of ~~Marist~~St. Francis College in Brooklyn, New York and received an M.B.A. from Iona College.

Richard F. Ambury. Mr. Ambury has been Chief Financial Officer, Treasurer and Secretary of Kestrel Heat since April 28, 2006. Mr. Ambury was Chief Financial Officer, Treasurer and Secretary of Star Gas from May 2005 until April 28, 2006. From November 2001 to May 2005, Mr. Ambury was Vice President and Treasurer of Star Gas. From March 1999 to November 2001, Mr. Ambury was Vice President of Star Gas Propane, L.P. From February 1996 to March 1999, Mr. Ambury served as Vice President—Finance of Star Gas Corporation, predecessor general partner. Mr. Ambury was employed by Petro from June 1983 through February 1996, where he served in various accounting/finance capacities. From 1979 to 1983, Mr. Ambury was employed by a predecessor firm of KPMG, a public accounting firm. Mr. Ambury has been a Certified Public Accountant since 1981 and is a graduate of Marist College.

Steven J. Goldman. Mr. Goldman has been Senior Vice President of Operations of the Partnership since May 31, 2007. Mr. Goldman was Vice President of Operations of Petro Holdings, Inc. from July 2004 until May 31, 2007. From February 2000 to June 2004, Mr. Goldman held various operating management positions with Petro Holdings, Inc. Prior to joining Petro Holdings, Inc. as a General Manager in 2000, Mr. Goldman worked for United Parcel Service from 1982 to 2000. Mr. Goldman has also held various positions within the management of companies in industrial engineering and those with international operations. Mr. Goldman is a graduate of the State University of New York at Stony Brook.

Richard G. Oakley. Mr. Oakley has been Vice President and Controller of Kestrel Heat since May 22, 2006. From September 1982 until May 2006 he held various positions with Meenan Oil Co. LP, most recently that of Controller since 1993. Mr. Oakley is a graduate of Long Island University.

Henry D. Babcock. Mr. Babcock has been a director of Kestrel Heat since April 28, 2006. Mr. Babcock is Chairman of Train, Babcock Advisors LLC, a privately- owned registered investment advisor. He joined the firm in 1976, became a partner in 1980 and CEO in 1999. Prior to this, he ran an affiliated venture capital company that was active the in the U.S. and abroad. Mr. Babcock is a graduate of Yale University and received an MBA from Columbia University. He serves on the Education Leadership Council of Save the Children and is a director of the Caumsett Foundation.

C. Scott Baxter. Mr. Baxter has been a director of Kestrel Heat since April 28, 2006. Mr. Baxter is currently the Managing ~~Partner~~Director & ~~for~~Head ~~Green~~of ~~River~~ Global Energy ~~Partners,~~Group ~~LLC~~for Houlihan Lokey , headquartered in New York City. Prior to Houlihan, he was the Managing Partner for Green River isEnergy Partners, LLC. Green River was a principal investing firm, which ~~invests~~invested in public and private equity in energy and was founded in 2005. From 2002 to 2005, he was a founding partner of Baxter Bold & Company, a corporate energy M&A and private equity advisory firm. From 1999 through 2001, he was Head of Americas for the Global Energy Investment Banking Group of JPMorgan. From 1989 to 1999, Mr. Baxter worked for Salomon Smith Barney’s Global Energy Investment Banking Group where he was a Managing Director. Mr. Baxter holds a B.S. degree in Economics from Weber State University where he graduated cum laude, and received an MBA degree from the University of Chicago Graduate School of Business. From 2002 to 2005 Mr. Baxter was also an adjunct professor of finance at Columbia University’s Graduate School of Business.

Bryan H. Lawrence. Mr. Lawrence has been a director of Kestrel Heat since April 28, 2006 and as a manager of Kestrel since July, 2005. Mr. Lawrence is a founder and senior manager of Yorktown, the manager of the Yorktown group of investment partnerships, which make investments in companies engaged in the energy industry. The Yorktown partnerships were formerly affiliated with the investment firm of Dillon, Read & Co. Inc., where Mr. Lawrence ~~had been~~ was employed ~~since~~beginning in 1966, serving as a Managing Director until the merger of Dillon Read with SBC Warburg in September 1997. Mr. Lawrence also serves as a director of Approach Resources, Inc., Crosstex Energy, Inc., Hallador Petroleum Company (each a United States publicly traded company), Winstar Resources Ltd. (a Canadian public company) and certain non-public companies in the energy industry in which Yorktown partnerships hold equity interests. Mr. Lawrence also serves as a director of Crosstex Energy GP, LLC, the general partner of Crosstex Energy, L.P. (a United States publicly traded company). Mr. Lawrence is a graduate of Hamilton College and received an M.B.A. from Columbia University.

~~Sheldon~~49 B. Lubar. Mr. Lubar has been a director of Kestrel Heat since April 28, 2006 and a manager of Kestrel since July, 2005. Mr. Lubar has been Chairman of the board of Lubar & Co. Incorporated, a private investment and venture capital firm he founded, since 1977. He was Chairman of the board of Christiana Companies, Inc., a logistics and manufacturing company, from 1987 until its merger with Weatherford International in 1995. Mr. Lubar had also been Chairman of Total Logistics, Inc., a logistics and manufacturing company until its acquisition in 2005 by SuperValu Inc. He has served as a director of Grant Prideco, Inc., an energy services company, since 2000; Weatherford International, Inc., an energy services company, since 1995; Crosstex Energy, Inc. since January 2004 and Crosstex Energy GP, LLC, the General Partner of Crosstex Energy, L.P. He is also a director of several private companies. Mr. Lubar holds a bachelor’s degree in Business Administration and a Law degree from the University of Wisconsin-Madison. He was awarded an honorary Doctor of Commercial Science degree from the University of Wisconsin-Milwaukee.

William P. Nicoletti. Mr. Nicoletti has been a director of Kestrel Heat since April 28, 2006. Mr. Nicoletti was the non-executive chairman of the board of Star Gas from March 2005 until April 28, 2006. Mr. Nicoletti was a director of Star Gas from March 1999 until April 28, 2006 and was a director of Star Gas Corporation, the predecessor general partner from November 1995 until March 1999. He is Managing Director of Nicoletti & Company, Inc., a private investment banking firm. Mr. Nicoletti was formerly a senior officer and head of Energy Investment Banking for E. F. Hutton & Company, Inc., PaineWebber Incorporated and McDonald Investments, Inc. Mr. Nicoletti is a director of MarkWest Energy Partners, L.P., and SPI Petroleum, LLC. Mr. Nicoletti is a graduate of Seton Hall University and received an M.B.A. from Columbia University.

~~Meetings~~Sheldon B. Lubar. Mr. Lubar has been a director of Kestrel Heat since April 28, 2006 and ~~Compensation~~a manager of ~~Directors~~ Kestrel since July, 2005. Mr. Lubar has been Chairman of the board of Lubar & Co. Incorporated, a private investment and venture capital firm he founded, since 1977. He was Chairman of the board of Christiana Companies, Inc., a logistics and manufacturing company, from 1987 until its merger with Weatherford International in 1995. Mr. Lubar had also been Chairman of Total Logistics, Inc., a logistics and manufacturing company until its acquisition in 2005 by SuperValu Inc. He has served as a director of Crosstex Energy, Inc. since January 2004; Approach Resources, Inc. since June 2007 and Crosstex Energy GP, LLC, the General Partner of Crosstex Energy, L.P. He is also a director of several private companies. Mr. Lubar holds a bachelor’s degree in Business Administration and a Law degree from the University of Wisconsin-Madison. He was awarded an honorary Doctor of Commercial Science degree from the University of Wisconsin-Milwaukee.

~~During~~William ~~fiscal~~P. ~~2006~~Nicoletti. Mr. Nicoletti has been a director of Kestrel Heat since April 28, 2006. Mr. Nicoletti was the ~~Board~~non-executive chairman of ~~Directors~~the board of Star Gas ~~met~~from 15March ~~times~~2005 until April 28, 2006. Mr. Nicoletti was a director of Star Gas from March 1999 until April 28, 2006 and was a director of Star Gas Corporation, the ~~Board~~predecessor general partner from November 1995 until March 1999. Since February 1, 2009, he has been a Managing Director of ~~Directors~~Parkman Whaling LLC, a Houston, Texas based energy investment banking firm. Previously, he was Managing Director of ~~Kestrel~~Nicoletti & ~~Heat~~Company, ~~met~~Inc., ~~one~~a ~~time~~private investment banking firm. ~~All~~Mr. Nicoletti ~~Star~~was ~~Gas~~formerly ~~Directors attended~~a ~~each~~senior ~~meeting~~officer ~~except~~and ~~one~~head ~~former~~of ~~director~~Energy ~~did~~Investment ~~not~~Banking ~~attend~~for ~~one~~E. ~~meeting~~F. ~~Following~~Hutton & ~~its~~Company, ~~appointment~~Inc., asPaineWebber ~~general~~Incorporated and ~~partner~~McDonald Investments, ~~all~~Inc. ~~Kestrel~~Mr. Nicoletti ~~directors~~is ~~except~~a director of MarkWest Energy Partners, L.P. Mr. ~~Lubar~~Nicoletti ~~attended~~is ~~the~~a ~~Board~~graduate of ~~Directors~~Seton ~~meeting~~Hall University and received an M.B.A. from Columbia University.

~~Each~~Director ~~non-management~~Independence director, with the exception of Bryan Lawrence who has chosen not to receive any fees, receives an annual fee of $27,000 plus $1,500 for each regular meeting attended and $750 for each telephonic meeting attended. The Chairman of the Audit Committee receives an annual fee of $12,000 while other Audit Committees members receive an annual fee of $6,000. Each member of the Audit Committee receives $1,500 for every regular meeting attended and $750 for every telephonic meeting attended. The non-executive chairman of the Board receives an annual fee of $120,000.

It is the policy of the Board of Directors that the number of independent Directors that comprise the Board shall at all times equal at least three Directors or such higher number as may be necessary to comply with the applicable federal securities law requirements. For the purposes of this policy, “independent director” shall have the meaning set forth in Section 10A(m) of the Securities Exchange Act of 1934, as amended, any applicable stock exchange rules and the rules and regulations promulgated in the Partnership governance guidelines available on its webpage www.Star-Gas.com. Messrs. Nicoletti, Babcock, and Baxter are independent Directors.

Meetings of Directors

During fiscal 2009, the Board of Directors of Kestrel Heat, LLC met five times. All directors attended each meeting except for one meeting where one director did not attend.

Committees of the Board of Directors

Kestrel Heat, LLC’s Board of Directors has one standing committee, the Audit Committee. Its members are appointed by the Board of Directors for a one-year term and until their respective successors are elected. The NYSE corporate governance standards do not require limited partnerships to have a Nominating or Compensation Committee.

Audit Committee

William P. Nicoletti, Henry D. Babcock and C. Scott Baxter have been appointed to serve on the Audit Committee of the general partner’s Board of Directors., ~~Kestrel~~which ~~Heat’s Board of Directors~~ has adopted an Audit Committee Charter. Mr. Nicoletti serves as chairman of the Audit Committee. A copy of this charter is available on the Partnership’s website at www.Star-Gas.com or a copy may be obtained without charge by contacting Richard F. Ambury (203) 328-~~7300~~7310. The Audit Committee reviews the external financial reporting of the Partnership, selects and engages the Partnership’s independent registered public accountants and approves all non-audit engagements of the independent registered public accountants. ~~During fiscal 2006, the Audit Committee of Star Gas met three times and the Audit Committee of Kestrel Heat met four times. All members attended each meeting.~~

Members of the Audit Committee may not be employees of Kestrel Heat, LLC’s or its affiliated companies and must otherwise meet the New York Stock Exchange and SEC independence requirements for service on the Audit Committee. The Board of Directors has determined that Messrs. Nicoletti, Babcock and Baxter are independent directors in that they do not have any material relationships with the Partnership (either directly, or as a partner, shareholder or officer of an organization that has a relationship with the Partnership) and they otherwise meet the independence requirements of the NYSE and the SEC. The Partnership’s Board of Directors has also determined that at least one member of the Audit Committee, Mr. Nicoletti, meets the SEC criteria of an “audit committee financial expert.”

During fiscal 2009, the Audit Committee of Kestrel Heat, LLC met six times. All members attended each meeting except for two meetings where one director did not attend.

Reimbursement of Expenses of the General Partner

The general partner does not receive any management fee or other compensation for its management of the Partnership. The general partner is reimbursed for all expenses incurred on behalf of the Partnership, including the cost of compensation, which is properly allocable to the Partnership. The Partnership’s partnership agreement provides that the general partner shall determine the expenses that are allocable to the Partnership in any reasonable manner determined by the general partner in its sole discretion. In addition, the general partner and its affiliates may provide services to the Partnership for which a reasonable fee would be charged as determined by the general partner. There were no reimbursements in fiscal year 2009.

Adoption of Code of Business Conduct and Ethics

The Partnership has adopted a written Code of Business Conduct and Ethics that applies to the Partnership’s officers, directors and employees. A copy of the Code of Business Conduct and Ethics is available on the Partnership’s website at www.Star-Gas.com or a copy may be obtained without charge, by contacting ~~Richard~~Investor ~~F. Ambury~~Relations, (203) 328-~~7300~~7310.

~~Non-Management~~Section 16(a) Beneficial ~~Directors~~Ownership Reporting Compliance

~~The~~Based ~~non-management directors~~ on ~~the~~copies ~~Board~~ of ~~Directors~~reports offurnished ~~the~~to ~~general~~us, ~~partner~~we ~~are~~believe ~~Messrs.~~that ~~Babcock,~~during ~~Baxter,~~fiscal ~~Lawrence,~~year ~~Lubar~~2009, ~~Nicoletti~~all ~~and~~reporting ~~Vermylen.~~persons ~~The~~complied ~~non-management~~with ~~directors have selected Mr.~~the Section ~~Vermylen~~16(a) tofiling ~~serve~~requirements asapplicable ~~lead director~~ to ~~chair~~ ~~executive sessions of the non-management directors~~them. ~~Unitholders interested in contacting the non-management directors as a group may do so by contacting Paul A. Vermylen, Jr. c/o Star Gas Partners, L.P., 2187 Atlantic Street, Stamford, CT 06902.~~

39Non-Management Directors and Interested Party Communications

~~Table~~The non-management directors on the Board of ~~Contents~~Directors of the general partner are Messrs. Babcock, Baxter, Lawrence, Lubar, Nicoletti and Vermylen. The non-management directors have selected Mr. Vermylen, the Chairman of the Board, to serve as lead director to chair executive sessions of the non-management directors. Interested parties who wish to contact the non-management directors as a group may do so by contacting Paul A. Vermylen, Jr. c/o Star Gas Partners, L.P., 2187 Atlantic Street, Stamford, CT 06902.

Officer Certification Requirements

The Partnership’s chief executive officer submitted to the NYSE the CEO certification required pursuant to Section 303A 12(a) of the NYSE rules for the fiscal year ended September 30, ~~2005~~2008.

This annual report on Form 10-K includes as exhibits the certifications of the Partnership’s chief executive officer and chief financial officer required under Section 302 and Section 906 of the Sarbanes-Oxley Act of 2002 and the rules and regulations promulgated ~~thereunder~~there under.

ITEM 11.

EXECUTIVE COMPENSATION

~~The~~Compensation ~~following~~Discussion ~~table~~And ~~sets forth~~Analysis the annual salary, bonuses and all other compensation awards and payouts to the Chief Executive Officer and to the named executive officers for services rendered to the Partnership and its subsidiaries during the fiscal years ended September 30, 2006, 2005 and 2004.

	Year	Summary Compensation Table AnnualCompensation									RestrictedStockAwards	Long-TermCompensation
Name and Principal Position		Salary			Bonus (1)			OtherAnnualComp.				SecuritiesUnderlyingUARs	AllOtherComp.
Joseph P. Cavanaugh,	2006	$	275,000		$	220,000		$	34,040	(3)
Chief Executive Officer	2005	$	189,000		$	1,140,894	(2)	$	9,910	(3)
	2004	$	267,800		$	—		$	494,169	(3)
Daniel P. Donovan,	2006	$	300,000		$	240,000		$	12,985	(4)
President and Chief	2005	$	300,000		$	—		$	21,778	(4)		5,000
Operating Officer	2004	$	253,654		$	85,785		$	24,614	(4)		10,000
Richard F. Ambury	2006	$	236,333		$	240,000		$	12,492	(4)
Chief Financial Officer	2005	$	232,988		$	100,000		$	16,629	(4)		9,917
	2004	$	222,956		$	—		$	10,034	(4)		9,917
Richard G. Oakley	2006	$	162,730	(5)	$	50,000		$	7,729	(4)
Vice President - Controller

The Partnership’s Amended and Restated Agreement of Limited Partnership provides that the general partner of the Partnership, Kestrel Heat, LLC, shall conduct, direct and manage all activities of the Partnership. The limited liability company agreement of the general partner provides that the business of the general partner shall be managed by a Board of Directors. The responsibility of the Board is to supervise and direct the management of the Partnership in the interest and for the benefit of the Partnership’s unitholders. Among the Board’s responsibilities is to regularly evaluate the performance and to approve the compensation of the Chief Executive Officer and, with the advice of the Chief Executive Officer, regularly evaluate the performance and approve the compensation of key executives.

~~(1)~~As ~~Amounts~~a ~~represent~~limited ~~bonuses~~partnership ~~earned~~that is listed on the New York Stock Exchange, the Partnership is not required to have a Compensation Committee. Since the Chairman of the general partner and ~~accrued~~the majority of the Board are not employees, the Board determined that it has adequate independence to act in the ~~fiscal~~capacity ~~year~~of a Compensation Committee to establish and review the compensation of the Partnership’s executive officers and directors. The Board is comprised of Paul A. Vermylen Jr. (Chairman), Daniel P. Donovan (President and Chief Executive Officer), Henry D. Babcock, C. Scott Baxter, Bryan H. Lawrence, Sheldon B. Lubar, and William P. Nicoletti.

Throughout this Report, each person who served as chief executive officer (2“CEO”) Induring ~~connection~~fiscal ~~with~~2009, ~~the~~each ~~sale~~person ofwho ~~the~~served ~~propane~~as ~~segment~~chief infinancial ~~December~~officer ~~2004,~~(“CFO”) ~~the~~during ~~Partnership~~fiscal ~~paid~~2009 and the ~~segment’s~~two ~~then~~other ~~Chief~~most ~~Executive~~highly ~~Officer,~~compensated ~~Joseph~~executive ~~Cavanaugh~~officers serving at September 30, a2009 ~~bonus~~(there ~~equal~~being tono ~~three~~other executive ~~times~~officers ~~Mr.~~who ~~Cavanaugh’s~~earned ~~annual~~more ~~salary~~than ~~and~~$100,000 ~~bonus~~during ~~upon~~fiscal 2009) are referred to as the ~~successful~~“named ~~completion~~executive ofofficers” and are included in the ~~sale~~Summary Compensation Table below.

~~(3)~~In ~~These~~this ~~amounts~~Compensation ~~represent~~Discussion ~~company~~and ~~paid contributions under Petro’s 401(k) defined contribution retirement plan. In fiscal 2006~~Analysis, ~~other~~we ~~annual~~address the compensation ~~includes~~paid aor ~~Company~~awarded ~~reimbursement~~to ofMessrs. ~~$13~~Donovan,~~134~~ ~~for the payment of taxes. In fiscal 2004~~Ambury, ~~other annual compensation includes a $474~~Goldman,~~679~~ ~~distribution~~and ~~from the Partnership’s SERP retirement plan~~Oakley. We ~~Mr.~~refer ~~Cavanaugh~~to ~~became~~these ~~eligible~~executive inofficers ~~fiscal~~as ~~2004~~our to“named ~~receive~~executive ~~distributions from the SERP plan~~officers.”

~~(4)~~51 ~~These amounts represent company paid contributions under Petro’s 401(k) defined contribution retirement plan.~~

(5) Mr. Oakley was elected an officer of the Partnership in October 2006, but has been serving as its Controller since May 2006, and prior thereto served as Controller of Meenan Oil Co. LP.

~~Aggregated~~Compensation ~~Option/UAR~~decisions ~~Exercises~~for inthe ~~Last~~above ~~Fiscal~~officers ~~Year~~were ~~and~~made ~~Fiscal~~by ~~Year~~the ~~End~~Board ~~Option/UAR~~of ~~Values~~Directors of the Partnership.

~~None~~COMPENSATION PHILOSOPHY AND POLICIES

~~Long-Term~~The primary objectives of the Partnership’s compensation program, including compensation of the named executive officers, are to attract and retain highly qualified officers, employees and directors ~~Incentive~~and ~~Plans—Awards~~to reward individual contributions to our success. The Board of Directors considers the following policies in ~~Last~~determining ~~Fiscal~~the compensation of the named executive officers:

~~None~~• compensation should be related to the performance of the individual executive and the performance measured against both financial and non-financial achievements;

~~Equity~~• ~~Compensation~~compensation ~~Plan~~levels ~~Information~~should be competitive to ensure that we will be able to attract, motivate and retain highly qualified executive officers; and

~~None~~• compensation should be related to improving unitholder value.

~~Employment~~Compensation ~~Contracts~~Methodology ~~and Service Agreements~~

~~Agreement~~The elements of the Partnership’s compensation program for named executive officers are intended to provide a total incentive package designed to drive performance and reward contributions in support of business strategies at the Partnership and operating unit level. Subject to the terms of employment agreements that have been entered into with ~~Joseph~~the named executive officers, all compensation determinations are discretionary and subject to the decision-making authority of the Board of Directors. We do not use benchmarking as a fixed criteria to determine compensation. Rather, after subjectively setting compensation based on the above factors, we reviewed the compensation paid to officers holding similar positions at our peer group companies to obtain a general understanding of the reasonableness of base salaries and other compensation payable to our named executive officers. Our peer group of companies was comprised of the following companies: Amerigas Partners, L.P., ~~Cavanaugh~~Suburban Propane Partners, L.P., Inergy Holdings, L.P., Ferrellgas Partners, L.P. and Global Partners, L.P. We chose these companies because they are master limited partnerships that are engaged in the retail distribution of energy products like the Partnership.

InElements ~~connection with the sale~~ of ~~the propane segment in December 2004, the Partnership paid the segment’s then Chief~~ Executive ~~Officer,~~Compensation Joseph Cavanaugh, a bonus of $1,140,894 (equal to three times Mr. Cavanaugh’s annual salary and bonus) upon the successful completion of the sale. Upon completion of the sale, Mr. Cavanaugh’s position was terminated by the Partnership. Mr. Cavanaugh was subsequently employed by Inergy, the entity that acquired the propane segment, from December 2004 to March 2005 as President, of its Star Gas Division. Mr. Cavanaugh was appointed as the Chief Executive Officer of Star Gas, effective as of March 7, 2005, at an annual salary of $275,000.

For the fiscal year ended September 30, 2009, the principal components of compensation for the named executive officers were:

•

base salary;

•

annual discretionary profit sharing allocation;

•

long-term management incentive compensation plan; and

•

retirement and health benefits.

Under our compensation structure, the mix of base salary, discretionary profit sharing allocation and long-term compensation provided to each executive officer varies depending on their position. The base salary for each executive officer is the only fixed component of compensation. All other compensation, including annual discretionary profit sharing allocation and long-term incentive compensation, is variable in nature.

For the CEO and the CFO, approximately 50% of the annual compensation is in the form of base salary and approximately 50% is from the discretionary profit sharing allocation. For the Vice President of Operations, approximately 60% of the annual compensation is in the form of base salary and 40% is from the discretionary profit sharing allocations. For the Vice President- Controller, approximately 65% of the annual compensation is in the form of base salary and 35% is from the discretionary profit sharing allocations. Since (as described below) no amounts were payable in fiscal 2009 under the terms of the long-term incentive plan, the Partnership’s compensation allocation in fiscal 2009 was 100% base salary and annual discretionary profit sharing allocation. In future fiscal years, the Partnership will also consider the percentage of overall compensation to be allocated to the long term incentive plan awards based upon the Partnership’s expected ability to make distributions under this plan, as described below.

We believe that together all of our compensation components provide a balanced mix of base compensation and compensation that is contingent upon each executive officer’s individual performance and our overall performance. A goal of the compensation program is to provide executive officers with a reasonable level of security through base salary and benefits, while rewarding them through incentive compensation to achieve business objectives and create unitholder value. As a result, officers with lower overall compensation levels will tend to have a higher percentage of base compensation. We believe that each of our compensation components is important in achieving this goal. Base salaries provide executives with a base level of monthly income and security. Annual discretionary profit sharing allocations motivate executives to drive our financial performance. Long-term incentive awards link the interests of our executives with our unitholders, which motivates our executives to create unitholder value. In addition, we want to ensure that our compensation programs are appropriately designed to encourage executive officer retention, which is accomplished through all of our compensation elements.

Base Salary

The Board of Directors establishes base salaries for the named executive officers based on a number of factors, including:

•

The historical salaries for services rendered to the Partnership and responsibilities of the named executive officer.

•

The salaries of equivalent executive officers at our peer group companies.

•

The prevailing levels of compensation and cost of living in the location in which the named executive officer works.

In determining the initial base compensation payable to individual named executive officers when they are first hired by the Partnership, our starting point is the historical compensation levels that the Partnership has paid to officers performing similar functions over the past few years. We also consider the level of experience and accomplishments of individual candidates and general labor market conditions, including the availability of candidates to fill a particular position. When we make adjustments to the base salaries of existing named executive officers, we review the individual’s performance, the value each named executive officer brings to us and general labor market conditions.

Elements of individual performance considered, among others, without any specific weighting given to each element, include business-related accomplishments during the year, difficulty and scope of responsibilities, effective leadership, experience, expected future contributions to the Partnership and difficulty of replacement. While base salary provides a base level of compensation intended to be competitive with the external market, the base salary for each named executive officer is determined on a subjective basis after consideration of these factors and is not based on target percentiles or other formal criteria. Although we believe that base salaries for our named executive officers are generally competitive with the external market, we do not use benchmarking as a fixed criteria to determine base compensation. Rather, after subjectively setting base salaries based on the above factors, we review the compensation paid to officers holding similar positions at our peer group companies to obtain a general understanding of the reasonableness of base salaries and other compensation payable to our named executive officers. The Partnership also takes into account geographic differences for similar positions in the New York Metropolitan area. While cost of living is considered in determining annual increases, the Partnership does not typically provide full cost of living adjustments as salary increases are constrained by budgetary restrictions and the ability to fund the Partnership’s current cash needs such as interest expense, maintenance capital, income taxes and distributions.

Profit Sharing Allocations

The Partnership maintains a profit sharing pool for employees, including named executive officers, which in fiscal 2009 was equal to approximately 6.0% of the Partnership’s earnings before income taxes, depreciation and amortization, excluding items affecting comparability (“adjusted EBITDA”). The annual discretionary profit sharing allocations paid to the named executive officers are payable from this pool. The size of the pool fluctuates based upon upward or downwards changes in adjusted EBITDA. The amount of cash paid to the named executive officers under the plan is based on the target percentages of overall compensation described above under the caption “Elements of Executive Compensation.” Depending upon the size of the profit sharing pool, the amount paid to the named officers could be more or less.

There are no set formulas for determining the amount payable to our named executive officers from the profit sharing plan. Factors considered by our CEO and the Board in determining the level of bonus compensation generally include, without assigning a particular weight to any factor:

(i)

whether or not we achieved certain budgeted goals for the year and any material shortfalls or superior performances relative to expectations. Under the plan, no profit sharing was payable with respect to fiscal 2009 unless the Partnership achieved actual adjusted EBITDA for fiscal 2009 of at least 70% of the amount of budgeted adjusted EBITDA for fiscal 2009. The budget is developed annually using a bottom up process;

(ii)

the level of difficulty associated with achieving such objectives based on the opportunities and challenges encountered during the year and;

(iii)

significant transactions or accomplishments for the period not included in the goals for the year.

Our CEO takes these factors into consideration as well as the relative contributions of each of the named executive officers to the year’s performance in developing his recommendations for bonus amounts. Based on such assessment, our CEO submits recommendations to the Board of Directors for the annual profit sharing amounts to be paid to our named executive officers, for the Board’s review and approval. Similarly, the Chairman assesses the CEO’s contribution toward meeting the Partnership’s goals based upon the above factors, and recommends to the Board of Directors a bonus for the CEO it believes to be commensurate with such contribution.

The Board of Directors retains the ultimate discretion to determine whether the named executive officers will receive annual discretionary bonuses based upon the factors discussed above.

Long-Term Management Incentive Compensation Plan

The long-term compensation structure is intended to align the employee’s performance with the long-term performance of our unitholders. In fiscal 2007, following the Partnership’s recapitalization, the Board of Directors adopted the Management Incentive Compensation Plan (the “Plan”) for employees of the Partnership. Under the Plan, employees who participate shall be entitled to receive a pro rata share of an amount in cash equal to:

•

50% of the distributions (“Incentive Distributions”) of Available Cash in excess of the minimum quarterly distribution of $0.0675 per unit otherwise distributable to Kestrel Heat pursuant to the Partnership Agreement on account of its general partner units; and

•

50% of the cash proceeds (the “Gains Interest”) which Kestrel Heat shall receive from the sale of its general partner units (as defined in the Partnership Agreement), less expenses and applicable taxes.

The pro rata share payable to each participant under the Plan is based on the number of participation points as described under “Fiscal 2009 Compensation Decisions - Long-Term Management Incentive Plan.” The amount paid in Incentive Distributions is governed by the partnership agreement and the calculation of Available Cash. The Partnership was not required under its partnership agreement to make any distributions of available cash until after September 30, 2008. Commencing with the fiscal quarter ending December 31, 2008 (the first quarter of fiscal 2009), Available Cash from Operating Surplus (as defined in our partnership agreement) is distributed to the holders of the Partnership’s common units and general partner units in the following manner:

First, 100% to all common units, pro rata, until there has been distributed to each common unit an amount equal to the minimum quarterly distribution of $0.0675 for that quarter;

Second, 100% to all common units, pro rata, until there has been distributed to each common unit an amount equal to any arrearages in the payment of the minimum quarterly distribution for prior quarters (commencing with the quarter ended December 31, 2008);

Third, 100% to all general partner units, pro rata, until there has been distributed to each general partner unit an amount equal to the minimum quarterly distribution;

Fourth, 90% to all common units, pro rata, and 10% to all general partner units, pro rata, until each common unit has received the first target distribution of $0.1125; and

Finally, 80% to all common units, pro rata, and 20% to all general partner units, pro rata.

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 law and the terms of any debt agreements or other agreements to which we are subject. The Board of Directors of our general partner reviews the level of Available Cash each quarter based upon information provided by management.

To fund the benefits under the Plan, Kestrel Heat has agreed to forego receipt of the amount of Incentive Distributions that are payable to plan participants. For accounting purposes, amounts payable to management under this Plan will be treated as compensation and will reduce both EBITDA and net income but not adjusted EBITDA. Kestrel Heat has also agreed to contribute to the Partnership, as a contribution to capital, an amount equal to the Gains Interest payable to participants in the Plan by the Partnership. The Partnership is not required to reimburse Kestrel Heat for amounts payable pursuant to the Plan.

The Plan is administered by the Partnership’s Chief Financial Officer under the direction of the Board or by such other officer as the Board may from time to time direct. Determination of the employees that participate in the Plan is under the sole discretion of the Board of Directors. In general, no payments will be made under this plan if the Partnership is not distributing cash under the Incentive Distributions described above.

The Board of Directors reserves the right to amend, change or terminate the Plan at any time. Without limiting the foregoing, the Board of Directors reserves the right to adjust the amount of Incentive Distributions to be allocated to the Bonus Pool if in its judgment extenuating circumstances warrant adjustment from the guidelines, and to change the timing of any payments due thereunder at any time in its sole discretion.

While certain management employees have already been allocated participation points, the Partnership did not make any Incentive Distributions during fiscal 2009 so the plan participants, which include the named executives, did not receive any distributions under this plan during this period. With regard to the Gains Interest, Kestrel Heat has not given any indication that it will sell its General Partner Units within the next twelve months. Thus the Plan’s value attributable to the Gains Interest currently cannot be determined.

Retirement and Health Benefits

The Partnership offers a health and welfare and retirement program to all eligible employees. The named executive officers are generally eligible for the same programs on the same basis as other employees of the Partnership. The Partnership maintains a tax-qualified 401(k) retirement plan that provides eligible employees with an opportunity to save for retirement on a tax advantaged basis. Under the Partnership’s 401(k) plan, subject to IRS limitations, each participant can contribute from 1.0% to 17.0% of compensation. The Partnership makes a 4% (to a maximum of 5.5% for participants who had 10 or more years of service at the time the Defined Benefit Plans were frozen and who have reached the age 55) core contribution of a participant’s compensation and matches 2/3 of each amount a participant contributes up to a maximum of 2.0% of a participant’s compensation, also subject to IRS limitations.

In addition, the Partnership has two frozen defined benefit pension plans that were maintained for all its eligible employees, including the named executive officers. The present value of accumulated benefits under these frozen defined benefit pension plans for each named executive officer is provided in the table labeled, Pension Plans Pursuant to Which Named Executive Officers Have an Accumulated Benefit But Are Not Currently Accruing Benefits.

Fiscal 2009 Compensation Decisions

For fiscal 2009, the foregoing elements of compensation were applied as follows:

Base Salary

The following table sets forth each named executive officer’s base salary as of October 1, 2009 and the percentage increase in his base salary over October 1, 2008. The base salaries for our named executive officers were determined prior to fiscal 2009, based upon the factors discussed under the caption “Base Salary.” The increases in such base salaries that were granted in fiscal 2009 were generally intended to reflect continued improvement in the Partnership’s operating results. The average percentage increase in base salary for executives in our peer group was 4.1%.


Name	Salary		Percentage Over Prior Year
Daniel P. Donovan	$	391,000	2.1	%
Richard F. Ambury	$	306,000	2.0	%
Steven Goldman	$	287,000	2.1	%
Richard G. Oakley	$	205,600	3.0	%

Annual Discretionary Profit Sharing Allocation

Based on our CEO’s annual performance review and the individual performance of each of our named executive officers, our Board approved the annual profit sharing allocation reflected in the “Summary Compensation Table” and notes thereto. The aggregate profit sharing amounts reflected in the Summary Compensation Table are approximately 88.3% higher than the bonus amounts for fiscal 2008. One of the Partnership’s primary performance measure is Adjusted EBITDA. Adjusted EBITDA for fiscal year 2009 increased by $30.3 million or, 54.5%, to $85.8 million. The average percentage increase in EBITDA for companies in our peer group was 13.8%.

Long-Term Management Incentive Compensation Plan

In October 2006, the Board awarded 1,000 participation points in the Plan to certain officers, including the following points to the following current and former named executive officers: Joseph Cavanaugh - 233 1/3, Dan Donovan - 233 1/3, Richard Ambury - 233 1/3, and Steven Goldman - 100.

In fiscal year 2007, Mr. Cavanaugh’s points were reallocated upon his retirement as provided for in the Plan and additional participation points were given to certain officers, increasing the Plan’s total participation points to 1,025. The named executive officers have participation points in the Plan are as follows: Dan Donovan - 300, Richard Ambury - 235, Steven Goldman - 150, and Richard Oakley - 30.

The participation points were awarded based on the length of service and level of responsibility of the named executive and the Partnership’s desire to retain the named executives, which is in the long-term best interest of the Partnership. In general, the largest awards were granted to the CEO and CFO, who were the most senior participants in the plan and each of whom had more than 25 years service with the Partnership and lesser awards were granted to the remaining participants, based upon their level of responsibility and length of service, without using a fixed formula to set such awards.

In fiscal 2009, no additional participation points were awarded under the Plan and no amounts were paid to the named executive officers.

Retirement and Health Benefits

There were no changes to the retirement and health benefits applicable to the named executive officers in fiscal 2009.

Employment Contracts and Severance Agreements

Agreement with Daniel P. Donovan

The Partnership entered into an employment agreement with Mr. Donovan effective as of May 531, ~~2004~~2007. Mr. Donovan’s employment agreement has a term of three-years ending on ~~July~~May 1231, ~~2007~~2010, or unless otherwise terminated in accordance with the employment agreement. ~~The employment agreement provides for an annual base salary of $300,000. In addition,~~ Mr. Donovan ~~may~~will ~~earn~~serve aas ~~bonus~~President ofand upChief toExecutive ~~40%~~Officer of ~~his~~the ~~base~~Partnership ~~salary~~and ~~for~~its ~~services rendered based upon achieving certain performance criteria~~subsidiaries. ~~Mr. Donovan will also be entitled to receive 10,000 common units annually under a long-term incentive plan that is to be developed by the Partnership.~~ The employment agreement provides for one year’s salary as severance if Mr. Donovan’s employment is terminated without cause or by Mr. Donovan for good reason.

Agreement with Richard F. Ambury

~~Effective May 4,~~The ~~2005,~~Partnership ~~Petro~~ entered into an employment agreement with ~~Richard F. Ambury pursuant to which~~ Mr. Ambury ~~will~~effective beas ~~employed~~of ~~by Petro for a three-year term ending on May~~April 328, 2008. Mr. Ambury will serve as ~~Vice President and~~ Chief Financial Officer ~~of both Petro~~ and ~~the~~Treasurer ~~general partner~~ of the Partnership and its subsidiaries. The employment agreement provides for anone ~~annual~~year’s ~~base~~ salary ~~of $236,333 and a performance-based bonus of up to 40% of his base salary or such higher percentage~~ as ~~shall~~severance beif ~~applicable to Petro’s chief operating officer. In addition to the performance-based bonus,~~ Mr. Ambury ~~will receive a payment of $50,000 on the last day of each 12-month period during the term. If Mr. Ambury~~’s employment is terminated without cause or by Mr. Ambury ~~terminates his employment~~ for good reason~~, Mr~~. ~~Ambury~~ would be entitled to the following severance compensation: $572,666 if the agreement is terminated after May 1, 2006 and prior to April 30, 2007; and $286,333, if the agreement is terminated after May 1, 2007 and prior to May 3, 2008.

Agreement with Steven Goldman

Effective May 31, 2007 Steven Goldman was appointed the Senior Vice President of Operations of the Partnership. On December 3, 2007 Mr. Goldman entered into an employment agreement that provides for one year’s salary as severance if his employment is terminated without cause or by Mr. Goldman for good reason.

Agreement with Richard G. Oakley

Effective ~~May~~November 222, ~~2006~~2009, the Partnership entered into an ~~employment~~ agreement with Mr. Richard G. Oakley pursuant to which Mr. Oakley will continue to be employed ~~for a three-year term ending on May 21, 2009. Mr. Oakley will serve~~ as Vice President – —Controller ofon ~~the Partnership. The agreement provides for~~ an ~~annual~~at-will ~~base salary of $190~~basis,~~000~~ and ~~a performance-based bonus of up~~ toprovides ~~25%~~for ofone ~~his~~year’s ~~base~~ salary ~~or such higher percentage~~ as ~~may~~severance beif ~~applicable.~~his Ifemployment ~~the~~is ~~Partnership~~terminated ~~terminates Mr. Oakley’s employment~~ for reasons other than cause~~, he will be entitled to one year’s salary as severance~~.

~~401(k)~~Change ~~Plan~~In Control Agreements

~~Mr.~~On December ~~Cavanaugh~~4, 2007, the Board of Directors authorized the Partnership and our general partner to enter into a Change In Control Agreement with the following executive officers: Mr. Donovan, Chief Executive Officer and Mr. Ambury, ~~and~~Chief MrFinancial Officer. ~~Oakley~~ ~~are~~Under ~~covered~~the ~~under~~terms of each agreement, if the above mentioned executive officer’s employment is terminated as a ~~401(k)~~result ~~defined~~of ~~contribution~~a ~~plan~~change ~~maintained~~in bycontrol ~~Petro.~~(as ~~Participants~~defined in the ~~plan~~agreement) ~~may~~that ~~elect~~executive toofficer ~~contribute~~will be entitled to a ~~sum~~payment ~~not~~equal to ~~exceed~~two times their base annual salary in the ~~lesser~~year of ~~17%~~such oftermination aplus ~~participant’s~~two ~~compensation~~times the average amount paid as a bonus and/or as profit sharing during the ~~maximum limit~~three ~~under~~years preceding the ~~Internal~~year ~~Revenue~~of ~~Code~~such termination. The term change in control means the present equity owners of ~~1975,~~Kestrel asand ~~amended.~~their ~~Under~~affiliates ~~this~~collectively ~~plan,~~cease ~~Petro~~to ~~makes~~beneficially aown ~~core~~equity interests ~~contribution~~having ~~from~~the 4%voting uppower to elect at least a ~~maximum~~majority ~~5.5%~~of the members of athe ~~participant’s~~board ~~compensation~~of updirectors toor ~~$220,000~~other ~~and~~governing ~~matches~~board ~~2/3~~of the general partner of ~~each~~the ~~amount~~Partnership ~~that~~or any successor entity to the Partnership. If a ~~participant~~change in control were to ~~contributes~~have ~~with~~occurred as of the date of this report, Mr. Donovan would have received a ~~maximum~~payment ~~employer~~of ~~match~~$1.7 million and Mr. Ambury would have received a payment of 2%$1.3 million.

41Indemnification Agreements

We have entered into an indemnification agreement with each of our directors and senior executives. These agreements provide for us to, among other things, indemnify such persons against certain liabilities that may arise by reason of their status or service as directors or officers, to advance their expenses incurred as a result of a proceeding as to which they may be indemnified and to cover such person under any directors’ and officers’ liability insurance policy we choose, in our discretion, to maintain. These indemnification agreements are intended to provide indemnification rights to the fullest extent permitted under applicable indemnification rights statutes in the State of Delaware and are in addition to any other rights such person may have under our partnership agreement and the operating agreement of our general partner, and applicable law. We believe these indemnification agreements enhance our ability to attract and retain knowledgeable and experienced executives and independent, non-management directors.

~~Management~~Board ~~Incentive~~of ~~Compensation~~Directors ~~Plan~~Report

OnThe ~~July 20, 2006, the~~ Board of Directors of ~~Kestrel Heat adopted a Management Incentive Compensation Plan (~~the ~~“Plan”)~~general ~~for~~partner ~~the Partnership. Under the Plan, certain management employees~~ of the Partnership ~~and~~does ~~its~~not ~~direct~~have ~~and~~a ~~indirect~~separate ~~subsidiaries~~compensation ~~that~~committee. ~~are~~Executive ~~selected~~compensation is determined by the Board toof ~~participate~~Directors. inMr. Donovan ~~the~~is ~~Plan~~President, ~~shall~~Chief beExecutive ~~entitled~~Officer toand ~~receive~~ a ~~pro~~Director. ~~rata share of an amount in cash up to:~~

•The ~~50%~~Board of Directors reviewed and discussed with the ~~Incentive~~Partnership’s ~~Distributions~~management ~~(as~~the ~~defined~~Compensation Discussion and Analysis contained in this annual report on Form 10-K. Based on that review and discussion, the ~~Partnership~~Board ~~Agreement)~~of ~~otherwise~~Directors ~~distributable~~recommends tothat ~~Kestrel~~the Compensation ~~Heat~~Discussion ~~pursuant~~and toAnalysis be included in the Partnership’s ~~Agreement;~~annual ~~and~~report on Form 10-K for the year ended September 30, 2009.

~~• 50% of the cash proceeds (the “Gains Interest”) which Kestrel Heat shall receive from the sale of its General Partner Units (as defined in the Partnership Agreement)~~Paul A. Vermylen, ~~less expenses and applicable taxes~~ Jr.

~~To fund the benefits under the Plan, Kestrel Heat has agreed to forego receipt of up to 50% of all distributions to which it would be entitled in excess of minimum quarterly distributions~~Daniel P. Donovan Amounts payable to management under this Plan will be treated as compensation and will reduce both EBITDA and net income. Kestrel Heat has also agreed to contribute to the Partnership, as a contribution to capital, an amount equal to the Gains Interest payable to participants in the Plan by the Partnership.

~~The~~Henry ~~Plan is administered by the Partnership’s Chief Financial Officer under the direction of the Board or by such other officer as the Board may from time to time direct~~D. Babcock

In October 2006, the Board awarded 1,000 participation points in the Plan to certain officers, including the following points to the following named executive officers: Joseph Cavanaugh-233 1/3; Dan Donovan-233 1/3; and Richard Ambury-233 1/3C. ~~This~~Scott ~~would~~Baxter ~~entitle each of them to receive approximately 23% of any amounts distributed under the Plan during the 2007 fiscal year.~~

Bryan H. Lawrence

Sheldon B. Lubar

William P. Nicoletti

Executive Compensation Table

The following table sets forth the annual salary compensation, bonus and all other compensation awards earned and accrued by the named executive officers in the fiscal year.


	Summary Compensation Table
Name and Principal Position	Fiscal Year	Salary		Bonus		Unit Awards	Option Awards	Non- Equity Incentive Plan Comp.		Change in Pension Value and Nonqualified Deferred Comp. Earnings(1)			All Other Comp.(2)		Total
Daniel P. Donovan	2009	$	388,333			—	—	$	615,000	$	181,947		$	38,004	$	1,223,284
President and Chief Executive Officer	2008	$	377,667			—	—	$	330,000	$	(33,326	)	$	33,321	$	707,662
President and Chief Executive Officer	2007	$	325,288	$	375,000	—	—			$	6,665		$	32,905	$	739,858

Richard F. Ambury	2009	$	302,500			—	—	$	485,000	$	64,798		$	30,722	$	883,020
Chief Financial Officer	2008	$	292,028			—	—	$	260,000	$	(19,423	)	$	27,855	$	560,460
	2007	$	286,333	$	286,000	—	—			$	(4,043	)	$	22,624	$	590,914

Steven J. Goldman	2009	$	285,000			—	—	$	337,000	$	—		$	33,404	$	655,404
Senior Vice President of Operations	2008	$	277,000			—	—	$	182,000	$	—		$	30,085	$	489,085
Senior Vice President of Operations	2007	$	244,561	$	200,000	—	—			$	—		$	29,415	$	473,976

Richard G. Oakley	2009	$	199,600			—	—	$	150,000	$	88,066		$	29,284	$	466,950
Vice President - Controller	2008	$	195,700			—	—	$	84,000	$	(27,678	)	$	26,657	$	278,679
	2007	$	190,000	$	96,000	—	—			$	(6,595	)	$	26,703	$	306,108

(1)	The Partnership has two frozen defined benefit pension plans where participants are not accruing additional benefits. The change in the named executive’s pension values are non-cash, and reflect normal adjustments resulting from changes in discount rates and government mandated mortality tables.

(2)	All other compensation is subdivided as follows:


Name	Company Match and Core Contribution to 401 (K) Plan ($)	Car Allowance or Monetary Value for Personal Use of Company Owned Vehicle ($)	Total ($)
Daniel P. Donovan	20,679	17,325	38,004
Richard F. Ambury	15,272	15,450	30,722
Steven J. Goldman	16,532	16,872	33,404
Richard G. Oakley	15,734	13,550	29,284

Grants of Plan-Based Awards

None

Outstanding Equity Awards at Fiscal Year-End

None

Option Exercises and Stock Vested

None

Pension Plans Pursuant to Which Named Executive Officers Have an Accumulated Benefit But Are Not Currently Accruing Benefits


Name	Plan Name	Number of Years Credited Service	Present Value of Accumulated Benefit		Payments During Last Fiscal Year
Daniel P. Donovan	Retirement Plan	21	$	705,450	$	—
Richard F. Ambury	Retirement Plan	13	$	126,689	$	—
	Supplemental Employee Retirement Plan	—	$	24,246	$	—
Steve Goldman	Retirement Plan	—	$	—	$	—
Richard G. Oakley	Retirement Plan	19	$	189,873	$	—

Nonqualified Defined Contribution and Other Nonqualified Deferred Compensation Plans

None

Potential Payments upon Termination

If Mr. Donovan’s employment is terminated by the Partnership for reasons other than for cause or if Mr. Donovan terminates his employment for good reason prior to May 31, 2010, he will be entitled to receive one-year’s salary as severance except in the case of a termination following a change in control which is discussed above under “Change in Control Agreements.” For 12 months following the termination of his employment, Mr. Donovan is prohibited from competing with the Partnership or from becoming involved either as an employee, as a consultant or in any other capacity, in the sale of heating oil or propane on a retail basis.

If Mr. Ambury’s employment is terminated for reasons other than cause or if Mr. Ambury terminates his employment for a good reason, he will be entitled to receive a severance payment of one year’s salary except in the case of a termination following a change in control which is discussed above under “Change in Control Agreements.” For 12 months following the termination of his employment, Mr. Ambury is prohibited from competing with the Partnership or from becoming involved either as an employee, as a consultant or in any other capacity, in the sale of heating oil or propane on a retail basis.

If Mr. Goldman’s employment is terminated by the Partnership for reasons other than for cause, or if Mr. Goldman terminates his employment for good reason, he will be entitled to receive one-years salary as severance. For 12 months following the termination of his employment, Mr. Goldman is prohibited from competing with the Partnership or from becoming involved either as an employee, as a consultant or in any other capacity, in the sale of heating oil or propane on a retail basis.

If Mr. Oakley’s employment is terminated by the Partnership without cause, he will be entitled to receive one-year’s salary as severance. For 12 months following the termination of his employment, Mr. Oakley is prohibited from competing with the Partnership or from becoming involved either as an employee, as a consultant or in any other capacity, in the sale of heating oil or propane on a retail basis.

The amounts shown in the table below assume that the triggering event for each named executive officer’s termination or change in control payment was effective as of the date of this report based upon their historical compensation arrangements as of such date. The actual amounts to be paid out can only be determined at the time of such named executive officer’s termination of employment or the Partnerships’ change of control.


Name	Potential Payments Upon Termination		Potential Payments Following a Change of Control
Daniel P. Donovan	$	391,000	$	1,662,000
Richard F. Ambury	$	306,000	$	1,299,333
Steve Goldman	$	287,000	$	—
Richard G. Oakley	$	205,600	$	—

The employment agreements of the foregoing officers also require that they not reveal confidential information of the Partnership within twelve months following the termination of their employment.

Compensation of Directors


	Director Compensation Table
Name	Fees Earned or Paid in Cash		Unit Awards	Option Awards	Non-Equity Incentive Plan Compensation	Change in Pension Value and Nonqualified Deferred Compensation Earnings (6)		All Other Compensation	Total
Paul A. Vermylen, Jr. (1)	$	126,750	—	—	—	$	180,121	—	$	306,871
Daniel P. Donovan (2)		—	—	—	—		—	—	$	—
Henry D. Babcock (3)	$	44,250	—	—	—		—	—	$	44,250
C. Scott Baxter (3)	$	42,750	—	—	—		—	—	$	42,750
Bryan H. Lawrence (4)		—	—	—	—		—	—	$	—
Sheldon B. Lubar	$	30,000	—	—	—		—	—	$	30,000
William P. Nicoletti (5)	$	50,250	—	—	—		—	—	$	50,250

(1)	Mr. Vermylen is non-executive Chairman of the Board.

(2)	Mr. Donovan is a management director and the change in his pension value is already included in the summary compensation table.

(3)	Mr. Babcock and Mr. Baxter are Audit Committee members.

(4)	Mr. Lawrence has chosen not to receive any fees as a director of the general partner of the Partnership.

(5)	Mr. Nicoletti is Chairman of the Audit Committee.

(6)

Mr. Vermylen had participated in one of the Partnership’s frozen defined benefit pension plans. Participants are currently not accruing additional benefits under the frozen plan. The change in the pension value reflects normal non-cash adjustments resulting from changes in discount rates and government mandated mortality tables.

Each non-management director receives an annual fee of $27,000 plus $1,500 for each regular meeting attended and $750 for each telephonic meeting attended. The Chairman of the Audit Committee receives an annual fee of $12,000 while other Audit Committees members receive an annual fee of $6,000. Each member of the Audit Committee receives $1,500 for every regular meeting attended and $750 for every telephonic meeting attended. The non-executive chairman of the Board receives an annual fee of $120,000.

ITEM 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table shows the beneficial ownership as of ~~December~~November 1430, ~~2006~~2009 of common units and general partner units by:

(1) Kestrel and certain beneficial owners;

(2) each of the named executive officers and directors of Kestrel Heat;

(3) all directors and executive officers of Kestrel Heat as a group; and

(4) each person the Partnership knows to hold 5% or more of the Partnership’s units.

Except as indicated, the address of each person is c/o Star Gas Partners, L.P. at 2187 Atlantic Street, Stamford, Connecticut 06902-0011.

	Common Units			General Partner Units
Name	Number	Percentage		Number	Percentage
Kestrel (a)	12,803,128	1617.9085	%	325,729	100.00	%
Paul A. Vermylen, Jr.	—155,000	—*
Joseph P. Cavanaugh	—	—
Daniel P. Donovan	19,500	*
Daniel P. Donovan	—	—
Steven J. Goldman	5,000	*
Richard F. Ambury	212,125	*
Richard G. Oakley	—	—
Henry D. Babcock	4196,121	*
C. Scott Baxter	—75,000	—*
Bryan H. Lawrence	—	—
Sheldon B. Lubar	—	—
William P. Nicoletti	2035,~~252~~000	*
All officers and directors and Kestrel Heat, LLC as a group (10 persons)	1213,~~866~~200,~~626~~874	1618.9841	%	325,729	100.00	%
MacKay Shields, LLC (b)	8,808,932	11.63	%
Bandera Partners LLC (b)	5,020,000	7.00	%

(a)	Includes (i) 500,000 common units and 325,729 general partner units owned by Kestrel Heat, and (ii) 12,303,128 common units owned by KM2, as to which Kestrel, in its capacity as sole member of Kestrel Heat and KM2, may be deemed to share beneficial ownership.

42(b) According to a Schedule 13G/A filed with the SEC on February 13, 2009, Bandera Partners LLC is the investment manager of Bandera Master Fund and may be deemed to have beneficial ownership of the common units.

(b) According to a Schedule 13G filed with the SEC on May 8, 2006, MacKay Shields, LLC an investment adviser for various clients registered under Section 203 of the Investment Advisers Act of 1940, is deemed to be the beneficial owner of the common units.

*	Amount represents less than 1%.

Section 16(a) of the Securities Exchange Act of 1934 requires the General Partner’s officers and directors, and persons who own more than 10% of a registered class of the Partnership’s equity securities, to file reports of beneficial ownership and changes in beneficial ownership with the Securities and Exchange Commission (“SEC”). Officers, directors and greater than 10 percent unitholders are required by SEC regulation to furnish the General Partner with copies of all Section 16(a) forms.

Based solely on its review of the copies of such forms received by the General Partner, or written representations from certain reporting persons that no Section 16 Forms were required for those persons, the General Partner believes that during fiscal 2006 all filing requirements applicable to its officers, directors, and greater than 10 percent beneficial owners were met in a timely manner.

ITEM 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

The Partnership has a written conflict of interest policy and procedure that requires all officers, directors and employees to report to senior corporate management or the board of directors, all personal, financial or family interest in transactions that involve the individual and the Partnership. In addition, the Partnership Governance Guidelines provide that any monetary arrangement between a director and his or her affiliates (including any member of a director’s immediate family) and the Partnership or any of its affiliates for goods or services shall be subject to approval by the full Board of Directors.

Kestrel has the ability to elect the Board of Directors of Kestrel Heat, including Messrs. Vermylen, Lawrence and Lubar. Messrs. Vermylen, Lawrence and Lubar are also members of the board of managers of Kestrel and, either directly or through affiliated entities, own equity interests in Kestrel. Kestrel owns all of the issued and outstanding membership interests of Kestrel Heat and KM2, LLC, a Delaware limited liability company (“M2”). ~~Kestrel Heat and M2 purchased an aggregate of 12,722,523 common units in connection with the recapitalization.~~

OnPolicies ~~April 26,~~Regarding ~~2006,~~Transactions ~~Mr. Vermylen~~with ~~contributed~~Related ~~50,000~~Persons common units that he owned prior to the commencement of the negotiation of the recapitalization to Kestrel and an additional 30,605 common units acquired upon exercise of the rights, in exchange for additional membership interests in Kestrel. Kestrel, in turn, contributed the 80,605 common units to M2.

~~ITEM~~Our ~~14.~~Code ~~PRINCIPAL~~of ~~ACCOUNTANT~~Business Conduct ~~FEES~~and ~~AND~~Ethics, ~~SERVICES~~Partnership Governance Guidelines and Partnership Agreement set forth policies and procedures with respect to transactions with persons affiliated with the Partnership and the resolution of conflicts of interest, which taken together provide the Partnership with a framework for the review and approval of “transactions” with “related persons” as such terms are defined in Item 404 of regulation S-K.

~~The following~~For ~~table represents~~ the ~~aggregate~~years ~~fees~~ended ~~for~~September 30, ~~professional~~2009, ~~audit~~2008 ~~services~~and ~~rendered~~2007, ~~by KPMG LLP including fees for~~ the ~~audit of the~~ Partnership’s ~~annual~~had ~~financial~~no ~~statements~~related ~~for~~party ~~the~~transactions ~~fiscal~~or ~~years~~agreements ~~2006~~pursuant ~~and 2005, and for fees billed and accrued~~to ~~for~~Item 404 ~~other~~of ~~services~~regulation ~~rendered by KPMG LLP (in thousands)~~S-K.

	2006		2005
Audit Fees (1)	$	1,540	$	1,716
Audit-Related Fees (2)		65		139
Audit and Audit-Related Fees		1,605		1,855
Tax Fees (3)		653		390
Total Fees	$	2,258	$	2,245

Our Code of Business Conduct and Ethics applies to our directors, officers, employees and their affiliates. It deals with conflicts of interest (e.g., transactions with the Partnership), confidential information, use of Partnership assets, business dealings, and other similar topics. The Code requires officers, directors and employees to avoid even the appearance of a conflict of interest and to report potential conflicts of interest to the Director of Internal Audit.

~~(1)~~Our ~~Audit~~Partnership ~~fees~~Governance ~~were~~Guidelines ~~for~~provide ~~professional~~that ~~services~~any ~~rendered~~monetary inarrangement ~~connection~~between ~~with~~a ~~audits~~director and ~~quarterly~~his ~~reviews~~or ofher ~~the~~affiliates ~~consolidated~~(including ~~financial~~any ~~statements~~member of ~~the~~a ~~Partnership,~~director’s ~~review~~immediate offamily) and ~~preparation~~the ofPartnership ~~consents~~or ~~for~~any ~~registration~~of ~~statements~~its ~~filed~~affiliates ~~with~~for ~~the~~goods ~~Securities~~or services ~~and~~shall ~~Exchange~~be ~~Commission,~~subject ~~for~~to ~~review~~approval ofby the ~~Partnership’s~~full ~~tax~~Board ~~provision~~of ~~and~~Directors. ~~for~~Although ~~subsidiary~~the ~~statutory~~Partnership ~~audits.~~Governance ~~The~~Guidelines ~~fees~~by intheir ~~2005~~terms ~~also~~only ~~included~~apply ~~fees related~~ to ~~services~~directors ~~in connection with Section 404 of~~ the ~~Sarbanes-Oxley~~Board ~~Act~~intends ofto ~~2002.~~apply ~~Audit~~this ~~fees~~requirement ~~incurred~~to inofficers ~~connection with registration statements were $90,000~~ and ~~$95,000~~employees ~~for fiscal years 2006~~ and ~~2005,~~their ~~respectively~~affiliates.

43To the extent that the Board determines that it would be in the best interests of the Partnership to enter into a transaction with a related person, the Board intends to utilize the procedures set forth in the Partnership Agreement for the review and approval of potential conflicts of interest. Our Partnership Agreement provides that whenever a potential conflict of interest exists or arises between the General Partner or any of its Affiliates (including its directors, executive officers and controlling members), on the one hand, and the Partnership or any partner, on the other hand, any resolution or course of action in respect of such conflict of interest shall be permitted and deemed approved by all partners, and shall not constitute a breach of the Partnership Agreement, of any agreement contemplated therein, or of any duty stated or implied by law or equity, if the resolution or course of action is, or by operation of the Partnership Agreement is deemed to be, fair and reasonable to the Partnership.

Any conflict of interest and any resolution of such conflict of interest shall be conclusively deemed fair and reasonable to the Partnership if such conflict of interest or resolution is (i) approved by a committee of independent directors (the “Conflicts Committee”), (ii) on terms no less favorable to the Partnership than those generally being provided to or available from unrelated third parties or (iii) fair to the Partnership, taking into account the totality of the relationships between the parties involved (including other^, transactions that may be particularly favorable or advantageous to the Partnership).

The General Partner (including the Conflicts Committee) is authorized in connection with its determination of what is “fair and reasonable” to the Partnership and in connection with its resolution of any conflict of interest to consider:

(A)

the relative interests of any party to such conflict, agreement, transaction or situation and the benefits and burdens relating to such interest;

(B)

any customary or accepted industry practices and any customary or historical dealings with a particular person;

(C)

any applicable generally accepted accounting practices or principles; and

(2D) ~~Audit-related~~such ~~fees~~additional ~~were~~factors ~~principally~~as ~~for~~the ~~audits~~General ofPartner ~~financial~~(including ~~statements~~the ofConflicts ~~certain~~Committee) ~~employee~~determines ~~benefit~~in ~~plans,~~its ~~internal~~sole ~~controls~~discretion ~~reviews, other services related~~ to ~~financial~~be ~~accounting~~relevant, ~~and~~reasonable ~~reporting~~or ~~standards~~appropriate ~~and~~under ~~preparation for~~ the ~~Partnership’s compliance with Section 404 of the Sarbanes-Oxley Act of 2002~~circumstances.

~~(3)~~ITEM ~~Tax~~14. ~~fees~~PRINCIPAL ~~related~~ACCOUNTANT toFEES ~~services~~AND ~~for tax consultation and tax compliance.~~SERVICES

~~Audit~~The ~~Committee:~~following ~~Pre-Approval~~table ~~Policies~~represents ~~and Procedures. At its regularly scheduled and special meetings,~~ the ~~Audit~~aggregate ~~Committee~~fees offor ~~the~~professional ~~Board of Directors considers and pre-approves any~~ audit ~~and non-audit~~ services to berendered ~~performed~~ by ~~the~~KPMG ~~Partnership’s~~LLP ~~independent~~including ~~accountants.~~fees ~~The~~for ~~Audit~~the ~~Committee~~audit ~~has delegated to its chairman, an independent member~~ of the Partnership’s ~~Board~~annual offinancial ~~Directors,~~statements for the ~~authority~~fiscal years to2009 ~~grant~~and ~~pre-approvals~~2008, ofand ~~non-audit~~for ~~services provided~~fees ~~that~~billed ~~the~~and ~~service(s)~~accrued ~~shall~~for beother ~~reported~~services torendered ~~the~~by ~~Audit~~KPMG ~~Committee~~LLP at(in ~~its next regularly scheduled meeting~~thousands).

Promptly after the effective date of the Sarbanes-Oxley Act of 2002, the Audit Committee approved all non-audit services being performed at that time by the Partnership’s principal accountant. On June 18, 2003, the Audit Committee adopted its pre-approval policies and procedures. Since that date, there have been no non-audit services rendered by the Partnership’s principal accountants that were not pre-approved.


	2009		2008
Audit Fees ⁽¹⁾	$	1,510	$	1,548
Tax Fees ⁽²⁾		481		263

Total Fees	$	1,991	$	1,811

⁽¹⁾	Audit fees were for professional services rendered in connection with audits and quarterly reviews of the consolidated financial statements of the Partnership

⁽²⁾	Tax fees related to services for tax consultation and tax compliance.

Audit Committee: Pre-Approval Policies and Procedures. At its regularly scheduled and special meetings, the Audit Committee of the Board of Directors considers and pre-approves any audit and non-audit services to be performed by the Partnership’s independent accountants. The Audit Committee has delegated to its chairman, an independent member of the Partnership’s Board of Directors, the authority to grant pre-approvals of non-audit services provided that the service(s) shall be reported to the Audit Committee at its next regularly scheduled meeting. On June 18, 2003, the Audit Committee adopted its pre-approval policies and procedures. Since that date, there have been no audit or non-audit services rendered by the Partnership’s principal accountants that were not pre-approved.

PART IV

ITEM 15.

EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

1. Financial Statements

See “Index to Consolidated Financial Statements and Financial Statement Schedule” set forth on page F-1.

2. Financial Statement Schedule.

See “Index to Consolidated Financial Statements and Financial Statement Schedule” set forth on page F-1.

3. Exhibits.

See “Index to Exhibits” set forth on the following page.

INDEX TO EXHIBITS

ExhibitNumber	Incorp ~~by Ref~~byRef. to Exh.	Description
3.1	3.1(1)	Amended and Restated Certificate of Limited Partnership
4.1	99.1(2)	Second Amended and Restated Agreement of Limited Partnership
4.2	99.3(3)	Amendment No. 1 to Second Amended and Restated Agreement of Limited Partnership
4.3	~~99.1(3)~~*	~~Amended~~Amendment ~~and~~No. ~~Restated~~2 ~~Unit~~to ~~Purchase~~Second ~~Rights~~Amended ~~Agreement~~and ~~dated~~Restated asAgreement of ~~July~~Limited ~~20, 2006~~Partnership
4.4	99.1(3)	Amended and Restated Unit Purchase Rights Agreement dated as of July 20, 2006
4.5	4.4(17)	First Amendment to Amended and Restated Unit Purchase Rights Agreement dated as of June 7, 2007
4.6	(21)	Second Amendment to Amended and Restated Unit Purchase Rights Agreement dated May 21, 2009.
10.1	10.21(4)	June 2000 Star Gas Employee Unit Incentive Plan†
10.2	10.41(5)	Employment Agreement between Petro Holdings, Inc. and Daniel P. Donovan.†
10.3	10.1(6)	Interest Purchase Agreement for the sale of the propane operations
10.4	10.2(6)	Non-Competition Agreement with Inergy
10.5	10.35(7)	Credit Agreement dated December 17, 2004, between Petroleum Heat and Power Co., Inc. and JPMorgan Chase Bank, N.A., Bank of America, N.A., Wachovia Bank, National Association, General Electric Capital Corporation, Citizens Bank of Massachusetts and J. P. MorganSecurities, Inc.
10.6	99.1(8)	Amendment, dated as of November 2, 2005, to the Credit Agreement, dated as of December 17, 2004 among Petroleum Heat and Power Co., Inc. and JPMorgan Chase Bank, N.A., Bank of America, N.A., Wachovia Bank, National Association, General Electric Capital Corporation, and Citizens Bank of Massachusetts
10.7	99.2(9)	Letter Agreement and general release dated March 7, 2005 between Star Gas Partners L.P. and Irik P. Sevin †
10.8	10.1(10)	Employment Agreement dated May 4, 2005 between the Registrant and Richard F. Ambury†
10.9	99.1(11)	Unit Purchase Agreement dated as of December 5, 2005 among Star Gas Partners, L.P., Star Gas LLC, Kestrel Energy Partners, LLC, Kestrel Heat, LLC and KM2, LLC
10.10	99.2(2)	Indenture for the new senior notes
10.11	99.3(2)	Amended and Restated Indenture for the existing senior notes
10.12	10.60(12)	Second Amendment dated as of February 3, 2006 to Credit Agreement
10.13	99.2(3)	Management Incentive Compensation Plan†
10.14	99.4(3)	Form of Indemnification Agreement for Officers and Directors.
10.15	*	Approved Dealer / Contractor Agreement dated as of July 11, 2006 by and between AFC First Financial Corporation and Petro Holdings, Inc.
10.16	*	Employment Agreement dated May 17, 2006 between Star Gas Partners, L.P. and Richard G. Oakley.
10.17	*	Third Amendment dated as of October 30, 2006 to the Credit Agreement.
10.18	99.4(13)	Form of Amendment No. 1 to Indemnification Agreement.
10.19	*	Fourth Amendment and Waiver dated as of December 28, 2006 to the Credit Agreement.
14	*	Code of Business Conduct and Ethics
21	*	Subsidiaries of the Registrant

4564

23.1	*	Consent of KPMG LLP
ExhibitNumber	Incorp byRef. to Exh.	Description
10.3	10.1(6)	Interest Purchase Agreement for the sale of the propane operations
10.4	10.2(6)	Non-Competition Agreement with Inergy
10.5	99.2(9)	Letter Agreement and general release dated March 7, 2005 between Star Gas Partners L.P. and Irik P. Sevin†
10.6	99.1(11)	Unit Purchase Agreement dated as of December 5, 2005 among Star Gas Partners, L.P., Star Gas LLC, Kestrel Energy Partners, LLC, Kestrel Heat, LLC and KM2, LLC
10.7	99.2(2)	Indenture for the new senior notes
10.8	99.3(2)	Amended and Restated Indenture for the existing senior notes
10.9	99.2(3)	Management Incentive Compensation Plan†
10.10	99.4(3)	Form of Indemnification Agreement for Officers and Directors.
10.11	(14)	Approved Dealer / Contractor Agreement dated as of July 11, 2006 by and between AFC First Financial Corporation and Petro Holdings, Inc.
10.12	99.4(13)	Form of Amendment No. 1 to Indemnification Agreement.
10.13	99.1(16)	Employment Agreement between Star Gas Partners, L.P. and Daniel P. Donovan.†
10.14	(18)	Description of 2008 Profit Sharing Plan.†
10.15	(19)	Employment Agreement dated December 3, 2007 between Star Gas Partners, L.P. and Steven J. Goldman.†
10.16	(19)	Change in Control Agreement dated December 4, 2007 between Star Gas Partners, L.P. and Daniel P. Donovan.†
10.17	(19)	Change in Control Agreement dated December 4, 2007 between Star Gas Partners, L.P. and Richard F. Ambury.†
10.18	(20)	Employment Agreement dated April 28, 2008 between Star Gas Partners, L.P. and Richard Ambury†
10.19	(22)	Amended and Restated Credit Agreement dated as of July 2, 2009.
10.20	(23)	Agreement dated November 2, 2009 between Star Gas Partners, L.P. and Richard G. Oakley.†
14	(20)	Code of Business Conduct and Ethics
21	*	Subsidiaries of the Registrant
31.1	*	Certification of Chief Executive Officer, Star Gas Partners, L.P., pursuant to Rule 13a-14(a)/15d-14(a).(1)
31.2	*	Certification of Chief Financial Officer, Star Gas Partners, L.P., pursuant to Rule 13a-14(a)/15d-14(a).(1)
31.3	*	Certification of Chief Executive Officer, Star Gas Finance Company, pursuant to Rule 13a-14(a)/15d-14(a).(1)
31.4	*	Certification of Chief Financial Officer, Star Gas Finance Company, pursuant to Rule 13a-14(a)/15d-14(a).(1)
32.1	*	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002(1)
32.2	*	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002(1)

* Filed ~~herewith.~~Herewith

†	Employee compensation plan.

(1)	Incorporated by reference to an exhibit to the Registrant’s Quarterly Report on Form 10-Q filed with the Commission on May 9, 2006.

(2)	Incorporated by reference to an exhibit to the Registrant’s Form 8-K dated April 28, 2006.

(3)	Incorporated by reference to an exhibit to the Registrant’s Form 8-K dated July 20, 2006.

(4)	Incorporated by reference to the same Exhibit to Registrant’s Quarterly Report on Form 10-Q filed with the Commission on August 10, 2000.

(5) Incorporated by reference to ~~and~~an exhibit to the Registrant’s Annual Report on Form 10-K for the fiscal year ended September 30, 2004, filed with the Commission on December 14, 2004.

(6)	Incorporated by reference to an exhibit to the Registrant’s Current Report on Form 8-K dated November 18, 2004.

(7) ~~Incorporated~~Intentionally ~~by reference to an exhibit to Registrant’s Quarterly Report on Form 10-Q filed with the Commission on February 9, 2005~~Omitted.

(8) ~~Incorporated~~Intentionally ~~by reference to an exhibit to the Registrant’s Current Report on Form 8-K dated November 4, 2005~~Omitted.

(9)	Incorporated by reference to an exhibit to the Registrant’s Current Report on Form 8-K filed with the Commission on March 8, 2005.

(10) ~~Incorporated~~Intentionally ~~by reference to the an exhibit to Registrant’s Quarterly Report on Form 10-Q filed with the Commission on May 6, 2005~~Omitted.

(11)	Incorporated by reference to an exhibit to the Registrant’s Current Report on Form 8-K dated December 5, 2005.

(12) ~~Incorporated~~Intentionally ~~by reference to an exhibit to Registrant’s Quarterly Report on Form 10-Q filed with the Commission on February 7, 2006~~Omitted.

(13)	Incorporated by reference to an exhibit to the Registrant’s Current Report on Form 8-K dated October 19, 2006.

46(14) Intentionally Omitted.

(15)	Intentionally Omitted.

(16)	Incorporated by reference to an exhibit to the Registrant’s Current Report on Form 8-K dated June 1, 2007.

(17)	Incorporated by reference to an exhibit to the Registrant’s Current Report on Form 8-K dated June 8, 2007.

(18)	Incorporated by reference to an exhibit to the Registrant’s Current Report on Form 8-K dated October 22, 2007.

(19)	Incorporated by reference to an exhibit to the Registrant’s Annual Report on Form 10-K for the fiscal year ended September 30, 2007 filed with the Commission on December 7, 2007.

(20)	Incorporated by reference to an exhibit to the Registrant’s Annual Report on Form 10-K for the fiscal year ended September 30, 2008 filed with the Commission on December 10, 2008.

(21)	Incorporated by reference to an exhibit to the Registrant’s Current Report on Form 8-K dated May 21, 2009.

(22)	Incorporated by reference to an exhibit to the Registrant’s Current Report on Form 8-K dated July 7, 2009.

(23)	Incorporated by reference to an exhibit to the Registrant’s Current Report on Form 8-K dated November 3, 2009.

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the General Partner has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized:

STAR GAS PARTNERS, L.P. By: KESTREL HEAT, LLC (General Partner) By: /s/ ~~JOSEPH~~Daniel P. ~~CAVANAUGH~~Donovan ~~Joseph~~Daniel P. ~~Cavanaugh~~Donovan President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons in the capacities and on the date indicated:

Signature	~~Title~~	~~Date~~Title	Date
/s/ Joseph P. Cavanaugh Joseph P. Cavanaugh	Chief Executive Officer and Director Kestrel Heat, LLC	January 16, 2007
/s/ Daniel P. Donovan Daniel P. Donovan		President and Chief Executive Officer and Director Kestrel Heat, LLC	December 9, 2009
/s/ Daniel P. Donovan Daniel P. Donovan	President, Chief Operating Officer and Director Kestrel Heat, LLC	January 16, 2007
/s/ Richard F. Ambury Richard F. Ambury		Chief Financial Officer (Principal Financial Officer) Kestrel Heat, LLC	December 9, 2009
/s/ Richard F. Ambury Richard F. Ambury	Chief Financial Officer (Principal Financial Officer) Kestrel Heat, LLC	January 16, 2007
/s/ Richard G. Oakley Richard G. Oakley		Vice President—Controller (Principal Accounting Officer) Kestrel Heat, LLC	December 9, 2009
/s/ Richard G. Oakley Richard G. Oakley	Vice President – Controller (Principal Accounting Officer) Kestrel Heat, LLC	January 16, 2007
/s/ Paul A. Vermylen, Jr. Paul A. Vermylen, Jr.		Non-Executive Chairman of the Board and Director Kestrel Heat, LLC	December 9, 2009
/s/ Paul A. Vermylen, Jr. Paul A. Vermylen, Jr.	Non-Executive Chairman of the Board and Director Kestrel Heat, LLC	January 16, 2007
/s/ Henry D. Babcock Henry D. Babcock		Director Kestrel Heat, LLC	December 9, 2009
/s/ Henry D. Babcock Henry D. Babcock	Director Kestrel Heat, LLC	January 16, 2007
/s/ C. Scott Baxter C. Scott Baxter		Director Kestrel Heat, LLC	December 9, 2009
/s/ C. Scott Baxter C. Scott Baxter	Director Kestrel Heat, LLC	January 16, 2007
/s/ Bryan H. Lawrence Bryan H. Lawrence		Director Kestrel Heat, LLC	December 9, 2009
/s/ Bryan H. Lawrence Bryan H. Lawrence	Director Kestrel Heat, LLC	January 16, 2007
/s/ Sheldon B. Lubar Sheldon B. Lubar		Director Kestrel Heat, LLC	December 9, 2009
/s/ Sheldon B. Lubar Sheldon B. Lubar	Director Kestrel Heat, LLC	January 16, 2007
/s/ William P. Nicoletti William P. Nicoletti		Director Kestrel Heat, LLC	December 9, 2009
/s/ William P. Nicoletti William P. Nicoletti	Director Kestrel Heat, LLC	January 16, 2007

4767

SIGNATURE

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

STAR GAS FINANCE COMPANY By: (Registrant) By: /s/ ~~JOSEPH~~Daniel P. ~~CAVANAUGH~~Donovan ~~Joseph~~Daniel P. ~~Cavanaugh~~Donovan President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons in the capacities and on the date indicated:

Signature	~~Title~~	~~Date~~Title	Date
/s/ JOSEPH P. CAVANAUGH Joseph P. Cavanaugh	Chief Executive Officer and Director (Principal Executive Officer) Star Gas Finance Company	January 16, 2007
/s/ Daniel P. Donovan Daniel P. Donovan		President, Chief Executive Officer and Director (Principal Executive Officer) Star Gas Finance Company	December 9, 2009
/s/ RICHARD F. AMBURY Richard F. Ambury	~~Chief Financial Officer (Principal Financial Officer) Star Gas Finance Company~~	~~January~~Chief ~~16,~~Financial ~~2007~~Officer (Principal Financial Officer) Star Gas Finance Company	December 9, 2009
/s/ RICHARD G. OAKLEY Richard G. Oakley	~~Vice President - Controller (Principal Accounting Officer) Star Gas Finance Company~~	~~January~~Vice ~~16,~~President—Controller ~~2007~~(Principal Accounting Officer) Star Gas Finance Company	December 9, 2009

4868

STAR GAS PARTNERS, L.P. AND SUBSIDIARIES

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

AND FINANCIAL STATEMENT SCHEDULE

	~~Page~~	Page
Part II Financial Information:
~~Item 8—Financial Statements~~	Item 8—Financial Statements
Reports of Independent Registered Public Accounting Firm	F-2 – F-3
	Report of Independent Registered Public Accounting Firm	F-2
Consolidated Balance Sheets as of September 30, 2006 and September 30, 2005 (restated)	F-4
	Consolidated Balance Sheets as of September 30, 2009 and September 30, 2008	F-3
Consolidated Statements of Operations for the years ended September 30, 2006, September 30, 2005 (restated) and September 30, 2004 (restated)	F-5
	Consolidated Statements of Operations for the years ended September 30, 2009, September 30, 2008 and September 30, 2007	F-4
Consolidated Statements of Comprehensive Income (Loss) for the years ended September 30, 2006, September 30, 2005 (restated) and September 30, 2004 (restated)	F-6
	Consolidated Statements of Partners’ Capital and Comprehensive Income (Loss) for the years ended September 30, 2009, September 30, 2008 and September 30, 2007	F-5
Consolidated Statements of Partners’ Capital for the years ended September 30, 2006, September 30, 2005 (restated) and September 30, 2004 (restated)	F-7
	Consolidated Statements of Cash Flows for the years ended September 30, 2009, September 30, 2008 and September 30, 2007	F-6
Consolidated Statements of Cash Flows for the years ended September 30, 2006, September 30, 2005 (restated) and September 30, 2004 (restated)	F-8
	Notes to Consolidated Financial Statements	F-7 – F-27
Notes to Consolidated Financial Statements	F-9 – F-32
	Schedules for the years ended September 30, 2009, September 30, 2008 and September 30, 2007
Schedules for the years ended September 30, 2006, September 30, 2005 and September 30, 2004
	I. Condensed Financial Information of Registrant	F-28 – F-30
I. Condensed Financial Information of Registrant (restated)	F-33 – F-35
	II. Valuation and Qualifying Accounts	F-31
II. Valuation and Qualifying Accounts	F-36
	All other schedules are omitted because they are not applicable or the required information is shown in the consolidated financial statements or the notes therein.
All other schedules are omitted because they are not applicable or the required information is shown in the consolidated financial statements or the notes therein.

F - 1

STAR GAS PARTNERS, L.P. AND SUBSIDIARIES

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Partners of Star Gas Partners, L.P.:

We have audited the accompanying consolidated ~~financial~~balance ~~statements~~sheets of Star Gas Partners, L.P. and Subsidiaries (the “Partnership”) as ~~listed~~of inSeptember 30, 2009 and 2008, and the related consolidated ~~accompanying~~statements ~~index~~of operations, partners’ capital and comprehensive income (loss), and cash flows for each of the years in the three-year period ended September 30, 2009. In connection with our audits of the consolidated financial statements, we have also audited the financial statement schedules asI and II listed in the accompanying index. ~~These~~We also have audited the Partnership’s internal control over financial reporting as of September 30, 2009, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Partnership’s management is responsible for these consolidated financial statements, ~~and~~the financial ~~statement~~ statement schedules, ~~are~~for maintaining effective internal control over financial reporting, and for its assessment of the

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