Edgar Filing: STAR GAS FINANCE CO

FORM 10-K

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, 2010

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

For the transition period from to

Commission File Number: 001-14129

Commission File Number: 333-103873-01

STAR GAS PARTNERS, L.P.

STAR GAS FINANCE COMPANY

(Exact name of registrants as specified in its charters)


Delaware		06-1437793
Delaware		75-3094991
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

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

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. x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer,” and “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, 2010 was approximately $304,139,000. As of November 30, 2010, 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	67,077,553
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.

2010 FORM 10-K ANNUAL REPORT

TABLE OF CONTENTS


		Page
	PART I

Item 1.	Business		3
Item 1A.	Risk Factors		9
Item 1B.	Unresolved Staff Comments		18
Item 2.	Properties		18
Item 3.	Legal Proceedings—Litigation		18
Item 4.	Reserved		18

	PART II

Item 5.	Market for the Registrant’s Units and Related Matters		18
Item 6.	Selected Historical Financial and Operating Data		20
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		23
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk		45
Item 8.	Financial Statements and Supplementary Data		45
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		45
Item 9A.	Controls and Procedures		45
Item 9B.	Other Information		46

	PART III

Item 10.	Directors and Executive Officers of the Registrant		47
Item 11.	Executive Compensation		51
Item 12.	Security Ownership of Certain Beneficial Owners and Management		60
Item 13.	Certain Relationships and Related Transactions		60
Item 14.	Principal Accounting Fees and Services		62

	PART IV

Item 15.	Exhibits and Financial Statement Schedules		62

PART I

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 customers and retain existing customers, our ability to make strategic acquisitions, the impact of litigation, our ability to contract for our current and future supply needs, natural gas conversions, union relations and the outcome of union negotiations, the impact of current and future governmental regulations, including environmental, health, and safety regulations, the ability to attract and retain employees, customer credit worthiness, counterparty credit worthiness, marketing plans, general economic conditions and new technology. All statements other than statements of historical facts included in this Report including, without limitation, the statements under “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and elsewhere herein, are forward-looking statements. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to be correct and actual results may differ materially from those projected as a result of certain risks and uncertainties. These risks and uncertainties include, but are not limited to, those set forth under the heading “Risk Factors” and “Business 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 November 30, 2010, had outstanding 67.1 million common units (NYSE: “SGU”) representing a 99.5% limited partner interest in Star Gas Partners, and 0.3 million general partner units, representing a 0.5% general partner interest in Star Gas Partners.

The Partnership is organized as follows:

•

Our general partner 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”).

•

Our operations are conducted through Petro Holdings, Inc. (a Minnesota corporation that is our indirect wholly owned subsidiary) and its subsidiaries.

•

Star Gas Finance Company is our 100% owned subsidiary. Star Gas Finance Company serves as the co-issuer, jointly and severally with us, of our Rule 144A $125.0 million 8.875% Senior Notes (excluding discounts and premiums), which are due in 2017. We are dependent on distributions, including inter-company interest payments, from our subsidiaries to service our debt obligations. The distributions from our subsidiaries are not guaranteed and are subject to certain loan restrictions. Star Gas Finance Company has nominal assets and conducts no business operations. (See Note 6. - Long-Term Debt and Bank Facility Borrowings)

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/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.

Partnership structure

The following chart summarizes our partnership structure as of September 30, 2010.

LOGO

Recent Developments

On November 16, 2010, we completed a Rule 144A offering of $125.0 million in aggregate principal amount of senior notes due 2017. The notes will accrue interest at a rate of 8.875% and were priced at 99.350%, for total gross proceeds of $124.2 million. The net proceeds from the offering will be used to redeem on December 20, 2010 any and all of the Partnership’s outstanding 10.25% notes due 2013, which currently equate to approximately $82.5 million. All remaining cash will be utilized for general partnership purposes.

Business Overview

As of September 30, 2010, we sold home heating oil to approximately 404,000 full service residential and commercial home heating oil customers and propane to approximately 10,000 propane customers. We believe we are the largest retail distributor of home heating oil in the United States. We also sell home heating oil, gasoline and diesel fuel to approximately 35,000 customers on a delivery only basis. We install, maintain, and repair heating and air conditioning equipment for our customers and provide ancillary home services, including home security and plumbing, to approximately 11,000 customers. During fiscal 2010, total sales were comprised approximately 77% from sales of home heating oil; 15% from the installation and repair of heating and air conditioning equipment and ancillary services; and 8% 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 2010, sales to residential customers represented 89% of the retail heating oil gallons sold and 93% of heating oil gross profits.

We conduct our business through an operating subsidiary, Petro Holdings, Inc., utilizing over 30 local brand names such as Petro Heating & Air Conditioning Services and Meenan Oil. 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.

We offer several pricing alternatives to our residential customers, including a variable price (market based) option and a price-protected option, the latter of which either sets the maximum price or fixes the price that a customer will pay. Approximately 97% of our deliveries for our full service residential and commercial home heating oil customers are automatically scheduled based on ongoing weather conditions. In addition, we offer a “smart pay” budget payment plan in which homeowners’ estimated annual oil deliveries and service billings are paid for in a series of equal monthly installments. We use derivative instruments on a daily basis to mitigate our exposure to market risk associated with our price-protected offerings and the storing of our physical home heating oil inventory. Given our size, we are able to realize benefits of scale and seek to provide consistent, strong customer service.

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	*New Hampshire*
Baltimore	Worcester	Bronx	Rockingham
Harford		Queens	Strafford
Cecil	*New Jersey*	Kings
Anne Arundel	Salem	Richmond	*Maine*
Carroll	Gloucester	New York	York
Howard	Camden
Montgomery	Burlington	*Pennsylvania*	*Virginia*
North Calvert	Ocean	Philadelphia	Loudoun
Prince George’s	Monmouth	Bucks	Prince William
Calvert	Somerset	Montgomery	Fauquier
Charles	Middlesex	Chester	Stafford
Frederick	Mercer	Lancaster	Arlington
	Hunterdon	Lebanon	Fairfax
	Union	Lehigh
	Hudson	Northampton	*Washington, D.C.*
	Bergen	Berks	District of Columbia
	Essex	Monroe
	Passaic	Delaware
	Sussex	Perry
	Morris	Dauphin
	Warren	Cumberland
		York

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% (6.2 million of 7.7 million) of the households in the United States where heating oil is the main space-heating fuel and 31% (6.2 million of 20.0 million) 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 conversions for fiscal years 2010, 2009 and 2008 were 1.2%, 1.6% and 1.6%, respectively. 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 business 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 new regulations, working capital requirements and 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.

Business strategy

Our business strategy is to increase operating profits and cash flow by conservatively managing our operations and growing our customer base as a leading retail distributor of home heating oil and ancillary services. The key elements of this strategy include the following:

Deliver superior customer service. We are completely focused on providing the best customer service in our regions, with the aim of maximizing customer retention. To engage our employees and enhance their ability to provide superior customer service (and reduce gross customer losses), we require all employees to go through appropriate training—supplemented by customer service monitoring. Our Director of Quality Assurance is responsible for customer service evaluation and directs teams that conduct district quality assurance assessments. These assessments are focused on improving our performance in customer relations and retention—to drive customer service performance to the best level possible.

Continue to focus on operating efficiencies. We constantly work to reduce operating costs and streamline our operations through the elimination of redundant systems and appropriate reductions in overhead. By spreading certain administrative costs over a growing customer base, we believe we can continue to generate strong financial results.

Pursue select acquisitions. Our senior management team has developed expertise in identifying acquisition opportunities and integrating acquired customers into our operations. Through our acquisitions, we have been able to increase our presence in some of our existing geographic markets and selectively expand into new markets, while maintaining or improving our financial results. Our acquisition strategy has enabled us to achieve our current market position and offers us the ability to continue to achieve operating efficiencies and economies of scale.

Broaden products and services. We sell related and complementary products and services, such as air conditioning systems, plumbing services and home security systems, in order to leverage our organizational structure and improve our sales penetration within the existing customer base. We continue to increase the quality and breadth of our service offerings and believe that these actions will further enhance our position with existing and potential customers, allowing us to maintain or improve customer retention.

Seasonality

The following matters should be considered in analyzing our financial results. Our fiscal year ends on September 30. All references to quarters and years respectively in this document are to fiscal quarters and years unless otherwise noted. The seasonal nature of our business results in the sale of approximately 30% of our volume of home heating oil in the first fiscal quarter and 50% of our volume in the second fiscal quarter of each fiscal year, the peak heating season. As a result, we generally realize net income in our first and second fiscal quarters and net losses during our third and fourth fiscal quarters and we expect that the negative impact of seasonality on our third and fourth fiscal quarter operating results will continue. 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 96% residential customers and 4% commercial customers. Our residential customer receives small deliveries on average of 160 gallons and our commercial accounts receive larger deliveries on average of 350 gallons. Typically, we make four to six deliveries per customer per year. Currently, 97% of our deliveries are scheduled automatically and 3% 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 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. Approximately 38% of our residential home heating oil customers have 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 ceiling or a fixed per gallon price that the customer would pay over a defined period. Over the last several years, a greater number of our price protected customers have selected the ceiling plan over the fixed price plan.


	September 30,
	2010			2009			2008			2007
Variable		55.8	%		52.3	%		48.6	%		61.0	%
Ceiling		41.8	%		44.6	%		34.4	%		23.2	%
Fixed		2.4	%		3.1	%		17.0	%		15.8	%

		100.0	%		100.0	%		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 from 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 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 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 2010, we lost 19,800 accounts (net), or 5.0% of our home heating oil customer base as compared to fiscal 2009, where we lost 30,300 accounts (net), or 7.6% of our home heating oil customer base. Excluding customer gains and losses at the home heating oil operations that we acquired in fiscal 2010, which acquisitions were completed after the fall marketing initiatives, we lost 17,600 accounts (net), or 4.7% of our home heating oil customer base. In fiscal 2008, we lost 18,300 accounts (net), or 4.3% of our home heating oil customer base. Our net customer attrition decreased in fiscal 2010 when compared to fiscal 2009, largely due to a reduction in gross losses (which is reflective of customer turn-over). In fiscal 2010 gross losses decreased to 16.8%, as compared to 21.1% in fiscal 2009 and 19.1% in fiscal 2008. (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 as of September 30, 2010 have contracts with approximately 80 third-party terminals for the right to temporarily store heating oil at their facilities. Purchases are made under supply contracts or on the spot market. Including our own physical storage, we have entered into market price based contracts for approximately 68% of our retail home heating oil requirements for fiscal 2011. During fiscal 2010, Global Companies, Sunoco Inc., NIC Holding Corp. (Northville Industries) and BP North America provided 19.6%, 12.0%, 11.2% and 11.1% respectively, of our product purchases. Aside from these four suppliers, no single supplier provided more than 10% of our product supply during fiscal 2010. For fiscal 2011, we generally have supply contracts for similar quantities with Global Companies, Sunoco Inc., NIC Holding Corp. (Northville Industries) and BP North America. 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 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.

The Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 815-10-05 Derivatives and Hedging topic, established accounting and reporting standards requiring that derivative instruments be recorded at fair value and included in the consolidated balance sheet as assets or liabilities. 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. 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 non-cash gains and losses on our derivative instruments prior to their maturity.

Home Heating Oil Price Volatility

In recent years, the wholesale price of home heating oil has been extremely volatile, resulting in increased consumer price sensitivity to heating costs and increased gross customer attrition. Like any other market commodity, the price of home heating oil is generally impacted by many factors, including economic and geopolitical forces. The price of home heating oil is closely linked to the price refiners pay for crude oil, which is the principal cost component of home heating oil. The volatility in the wholesale cost of home heating oil, as measured by the New York Mercantile Exchange (“Nymex”) price per gallon for fiscal 2010, 2009, and 2008 by quarter, is illustrated by the following chart:


	Fiscal 2010				Fiscal 2009				Fiscal 2008
	Low		High		Low		High		Low		High
Quarter Ended
December 31	$	1.7810	$	2.1190	$	1.1983	$	2.8469	$	2.1596	$	2.7066
March 31		1.8860		2.2030		1.1331		1.6263		2.4188		3.1483
June 30		1.8720		2.3450		1.3147		1.8630		2.8797		3.9748
September 30		1.9160		2.2440		1.5038		1.9569		2.7197		4.1060

Acquisitions

From April 1 to September 30, 2010 (after the heating season), the Partnership completed five acquisitions and added approximately 56,100 home heating oil, propane and security accounts. While these acquisitions provided additional revenues in fiscal 2010, the Partnership’s profitability measures such as operating income and net income, were adversely impacted as product costs and operating expenses from these acquisitions have exceeded revenues, which is normal for this non-heating period. The fiscal 2010 acquisitions cost approximately $68.8 million, including $4.2 million of working capital. In fiscal 2009, we completed the purchase of 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 2008, we completed the purchase of 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 $2.6 million, reduced by $0.7 million of working capital credits.

Income Taxes—Valuation Allowance and Net Operating Loss Carry Forward

Based 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 our 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. Most of the $86.4 million benefit relating to the valuation allowance release related to Federal and State loss carry forwards (NOLs), insurance reserves, and the net operating book versus tax timing of intangible amortization.

At December 31, 2006, we had Federal NOLs of $160.8 million and at December 31, 2009, we had Federal NOLs of $51.7 million. Over this three year period, we utilized $36.4 million of Federal NOLs on average each year to offset our taxable income. We expect that over the next twelve to fifteen months, we will utilize substantially all of the remaining unlimited Federal NOLs. After we exhaust the Federal NOLs, the amount of cash taxes that we will pay will increase significantly and will reduce the annual amount of cash available for distribution to unitholders. For example, in calendar 2007, 2008 and 2009 we paid Federal cash taxes of $1.0 million, $0.6 million, and $0.7 million respectively. If we did not have the Federal NOLs available to us for calendar 2007, 2008 and 2009 our Federal cash taxes would have increased to $17.2 million, $11.1 million and $9.9 million for calendar 2007, 2008 and 2009 respectively.

Income taxes—book versus tax deductions

The amount of cash flow that we generate in any given year depends upon a variety of factors including the amount of cash income taxes that our subsidiaries will pay. The amount of depreciation and amortization that we deduct for book (i.e. financial reporting) purposes will differ from the amount that our subsidiaries can deduct for tax purposes. The table below compares the estimated depreciation and amortization for book purposes to the amount that our subsidiaries expect to deduct for tax purposes. (Our subsidiaries file their tax returns based on a calendar year. The amounts below are based on our fiscal year.)

Estimated depreciation and amortization expense


(in thousands) Fiscal year	Book		Tax
2011	$	19,586	$	30,835
2012		13,431		27,625
2013		10,224		24,339
2014		8,897		20,493
2015		8,032		17,597

Employees

As of September 30, 2010, we had 2,729 employees, of whom 810 were office, clerical and customer service personnel; 848 were equipment technicians; 388 were oil truck drivers and mechanics; 396 were management and 287 were employed in sales. Of these employees 909 are represented by 24 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 456 seasonal employees (305 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 3 union 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 or emission 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. Products stored and/or delivered by us and certain automotive waste products generated by our fleet are hazardous substances within the meaning of CERCLA or otherwise subject to investigation and cleanup under other environmental laws and regulations. While we have implemented programs and policies designed to address potential liabilities and costs under applicable environmental laws and regulations, failure to comply with such laws and regulations could result in civil or criminal penalties in cases of non-compliance or impose liability for remediation costs.

We have incurred and continue to incur costs to address soil and groundwater contamination at some of our locations, including legacy contamination at properties that we have acquired. A number of our properties are currently undergoing remediation, in some instances funded and/or by prior owners or operators contractually obligated to do so. To date, no material issues have arisen with respect to such prior owners or operators addressing such remediation, although we cannot assure you that this will continue to be the case. In addition, we have been subject to proceedings by regulatory authorities for alleged violations of environmental and safety laws and regulations. We do not expect any of these liabilities or proceedings of which we are aware to result in material costs to, or disruptions of, our business or operations.

In addition, transportation of our products 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.

ITEM 1A.

RISK FACTORS

You should consider carefully the risk factors discussed below, as well as all other information, as an investment in the Partnership involves a high degree of risk. Any of the risks described below could impair our business, financial condition and operating results, which could result in a partial or total loss of your investment.

We are subject to certain risks and hazards due to the nature of the business activities we conduct. The risks discussed below, any of which could materially and adversely affect our business, financial condition, cash flows, and results of operations, are not the only risks we face. We may experience additional risks and uncertainties not currently known to us or, as a result of developments occurring in the future, conditions that we currently deem to be immaterial may also materially and adversely affect our business, financial condition, cash flows and results of operations.

Current economic conditions could adversely affect our results of operations and financial condition.

Since 2008, economic conditions in the United States have experienced a downturn due to the sequential effects of the sub-prime lending crisis, general credit market crisis, the general unavailability of financing, collateral effects on the finance and banking industries, volatile energy prices, concerns about inflation, slower economic activity, decreased consumer confidence, reduced corporate profits and capital spending, adverse business conditions, increased unemployment, liquidity concerns and declines in housing prices and house sales.

Uncertainty about current economic conditions poses a risk as our customers may reduce or postpone spending in response to tighter credit, negative financial news and/or declines in income or asset values, which could have a material negative effect on the demand for our equipment and services and could lead to increased conservation and the possibility of certain of our customers seeking lower cost providers. Any increase in existing customers seeking lower cost providers and/or increase in our rejection rate of potential accounts because of credit considerations could increase our overall rate of net customer attrition. If adverse economic conditions persist, we 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.

We rely on the continued solvency of our derivative and insurance counterparties. We regularly use derivative instruments such as futures, options, and swap agreements, in order to mitigate our exposure to market risk associated with the purchase of home heating oil for our price-protected customers, physical inventory on hand, inventory in transit and priced purchase commitments. We insure ourself against catastrophic property and other losses with insurance companies.

The financial turmoil affecting the banking system and financial markets and the possibility that financial institutions may consolidate or go out of business have resulted in a tightening in the credit markets, a low level of liquidity in many financial markets, and extreme volatility in fixed income, credit, currency and equity markets that may also adversely affect our results of operations and financial condition. There could be a number of follow-on effects from the credit crisis on our business, including insolvency of key suppliers resulting in product delays and failure of derivative counterparties and other financial institutions negatively impacting our liquidity and financial condition.

If counterparties to our derivative instruments were to fail, our liquidity, results of operations and financial condition could be materially impacted, as we would be obligated to fulfill our operational requirement of purchasing, storing and selling home heating oil, while losing the mitigating benefits of economic hedges with a failed counterparty. If one of our insurance carriers should fail, our liquidity, results of operations and financial condition could be materially impacted, as we would have to fund any catastrophic loss. Currently, we have outstanding derivative instruments with the following counterparties: Cargill, Inc., Key Bank National Association, Bank of America, N.A., JPMorgan Chase Bank, NA, Societe Generale, Newedge USA, LLC, and Wachovia Bank, N.A. (Wells Fargo Bank, N.A.). Our primary insurance carrier is a subsidiary of Chartis, formerly known as American International Group.

Our operating results are subject to seasonal fluctuations.

Our operating results are subject to seasonal fluctuations since the demand for home heating oil is greater during the first and second fiscal quarter of our fiscal year, which is the peak heating season. The seasonal nature of our business has resulted on average in the last five years in the sale of approximately 30% of our volume of home heating oil in the first fiscal quarter and 50% of our volume in the second fiscal quarter of each fiscal year. As a result, we generally realize net income in our first and second fiscal quarters and net losses during our third and fourth fiscal quarters and we expect that the negative impact of seasonality on our third and fourth fiscal quarter operating results will continue.

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

Weather conditions in the Northeast and Mid-Atlantic regions in which we operate 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 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 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 that we generated during these periods. As of September 30, 2010, approximately 42.6% of our total home heating oil volume was sold to customers in New York State. In fiscal 2002, temperatures in

Central Park, New York City were an average of 22.7% warmer than in fiscal 2001 and 18.9% warmer than normal. To partially mitigate the adverse effect of warm weather on our cash flows, we have entered into a weather hedge contract with Renaissance Trading Ltd. under which we will receive a payment of $35,000 per degree-day, when the actual degree-days are less than the 10 year average by 7.5%. The hedge covers the period from November 1, 2010 through March 31, 2011 taken as a whole and has a maximum payout of $12.5 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 2010, 2009, and 2008 was approximately 5.0%, 7.6%, and 4.3%, respectively. Excluding customer gains and losses at the home heating oil operations that we acquired in fiscal 2010, which acquisitions were completed after the fall marketing initiatives, we lost 17,600 accounts (net), or 4.7% of our home heating oil customer base, as the decline in gross customer gains of 10,200 accounts was more than offset by the decline in gross customer losses of 22,800 accounts. This rate represents the net of our annual gross customer losses after gross customer gains. For fiscal 2010, 2009, and 2008 we had gross customer losses of 16.8%, 21.1%, and 19.1%, respectively, which were partially offset by gross customer gains during these periods of 11.9%, 13.5%, and 14.8%, 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. Customer losses are the result of various factors, including but not limited to:

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price competition;

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customer relocations;

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credit worthiness; and

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conversions to natural gas.

The continuing unprecedented volatility in the price of heating oil has intensified price competition and added to our difficulty in reducing net customer attrition.

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

Because 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.

Our home heating oil business is subject to substantial competition. Most of our district locations compete with numerous distributors, primarily on the basis of reliability of service, price and response to customer service 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 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 otherwise able to obtain. We also compete for retail customers with suppliers of alternative energy products, principally natural gas, propane and electricity. Our customer losses to natural gas conversions for fiscal years 2010, 2009, and 2008 were 1.2%, 1.6% and 1.6% respectively, which compares to an approximate 1.0% per annum loss in prior years.

If we are unable to compete effectively, we may lose existing customers or fail to acquire new customers, which would have a material adverse effect on our operating results and financial condition.

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 uses natural gas when it is available, and competition has also increased from alternative energy sources. Accordingly, future growth will depend on our ability to make acquisitions on economically acceptable terms. 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 not limited on the number of individual acquisitions or aggregate dollar amount of acquisitions we make in any fiscal year, but we are restricted from making any individual acquisition in excess of $25.0 million without the lenders’ approval. In

addition, to make an acquisition, we are required to have Availability (as defined in the revolving credit facility) of $40.0 million, on a historical pro forma and forward-looking basis. This covenant restriction may limit our ability to make acquisitions. Any acquisition may involve potential risks to us and ultimately to our unitholders, including:

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an increase in our indebtedness;

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an increase in our working capital requirements;

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our inability to integrate the operations of the acquired business;

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our inability to successfully expand our operations into new territories;

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

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

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the assumption of additional liabilities including environmental liabilities.

In 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.

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

On November 16, 2010, we completed a Rule 144A offering of $125.0 million in aggregate principal amount of senior notes due 2017. The notes will accrue interest at a rate of 8.875% and were priced at 99.350%, for total gross proceeds of $124.2 million. The net proceeds from the offering will be used to redeem on December 20, 2010 any and all of the Partnership’s outstanding 10.25% notes due 2013, which currently equate to approximately $82.5 million. Our substantial indebtedness and other financial obligations could:

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

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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;

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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;

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

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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 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.

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.

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

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

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

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

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

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

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

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reduced liquidity as a result of higher receivables and/or inventory balances as we must fund a portion of any increase in receivables, inventory and hedging costs from our 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) for working capital purposes subject to maintaining availability (as defined in the revolving credit facility) 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 use forward swaps with members of our lending group to manage market risk associated with our fixed price and ceiling 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 $6.2 million as of September 30, 2010 and $4.7 million as of September 30, 2009.

For our ceiling price customers and some of our fixed price customers, we purchase call options, which usually require us 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. We also purchase synthetic call options which require us to pay for these options as they expire.

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 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, 2010, 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, 2010, customer credit balances aggregated $68.8 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.

At September 30, 2010, we had approximately 146,000 customers, or 38% 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 on a timely basis, our liquidity could also be reduced.

Sudden and sharp oil price increases that cannot be passed on to customers may adversely affect our operating results.

The retail home heating oil industry is a “margin-based” business in which gross profit depends on the excess of retail sales prices per gallon over supply costs per gallon. Consequently, our profitability is sensitive to changes 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, when there are sudden and sharp increases in the wholesale cost of home heating oil, we may not be able to pass on these increases to customers through increased retail sales prices. In an effort to retain existing accounts and attract new customers we may offer discounts, which will impact the net per gallon gross margin realized.

A significant portion of our home heating oil volume is sold to price-protected customers (ceiling and fixed) 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 arrangement pre-establishing the ceiling sales price or a fixed price of home heating oil over a fixed period. When the customer makes a purchase commitment for the next period we currently purchase option contracts, swaps and futures contracts for a substantial majority of the heating oil that we expect to 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, per month. If 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, (including, for example, as a result of early terminations by fixed price customers) our hedging losses could be greater. Currently, we have elected not to designate our derivative instruments as hedging instruments under FASB ASC 815-10-05 Derivatives and Hedging topic, and the change in fair value of the derivative instruments is recognized in our statement of operations. Therefore, we could experience great volatility in earnings as these currently outstanding derivative contracts are marked to market and non-cash gains or losses are recorded in the statement of operations.

We may be adversely affected by the impact of financial reform legislation on derivatives.

The U.S. Congress has recently passed comprehensive financial reform legislation that requires regulated banks with derivatives trading units to spin them off and that requires substantially all derivatives be traded through a central clearing house, subject to margin requirements. This legislation could substantially increase our cost in using certain derivatives and could make such derivatives less available, which could subject us to additional risks to the extent we are not able to hedge the risks in another manner. The full impact of this legislation on us cannot be fully determined until the required rules implementing this legislation have been drafted and adopted by the Commodities Futures Trading Commission and the SEC.

Significant declines in the wholesale price of home heating oil may cause price-protected customers to renegotiate or terminate their arrangements which may adversely impact our gross profit and net income.

When the wholesale price of home heating oil declines significantly after a customer enters into a price protection 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 switch to a competitor. As a result of significant decreases in the price of home heating oil following the summer of 2008, many price protection 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.

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 our 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 that 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 workers’ compensation, automobile and general liability claims up to pre-established limits. In storing and delivering product to our customers, our operations are subject to operational hazards such as natural disasters, adverse weather, accidents, fires, explosions, hazardous materials releases, mechanical failures and other events beyond our control. If any of these events were to occur, we could incur substantial losses because of personal injury or loss of life, severe damage to and destruction of property and equipment, and pollution or other environmental damage resulting in curtailment or suspension of our related operations.

We establish reserves based upon expectations as to what our ultimate liability will be for claims using our historical developmental factors. We evaluate on an annual basis the potential for changes in loss estimates with the support of qualified actuaries. As of September 30, 2010, we had approximately $37.4 million of insurance reserves and had issued $40.2 million in letters of credit for current and future claims. The ultimate settlement of these claims could differ materially from the assumptions used to calculate the reserves, which could have a material effect on our results of operations.

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 matters. Such laws and regulations have become increasingly stringent over time. We may 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 those relating to 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. We have incurred and continue to incur costs to address soil and groundwater contamination at some of our locations. We cannot be sure that we have identified all such contamination, that we know the full extent of our obligations with respect to contamination of which we are aware, or that we will not become responsible for additional contamination not yet discovered. 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 our operations could, if adopted, increase our costs and/or require changes to our operations, which could have a material adverse effect on our 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 by Congress and the EPA to develop new federal laws and regulations 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 us and our 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, or impacts on our business of, 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.

Furthermore, laws and regulations that affect our operations continue to evolve at both the state and federal levels, which may ultimately increase our compliance costs. 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. (See also the risks discussed above under the heading “We may be adversely affected by the impact of financial reform legislation on derivatives.”)

We 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.

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.

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 us and our limited partners and noteholders, 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 us or any of our limited partners and noteholders, 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 and noteholders. The nature of these conflicts is ongoing and includes the following considerations:

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

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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.

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

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

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

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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.

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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.

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

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The general partner determines which costs are reimbursable by us.

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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 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 a decrease in supply.

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, Star Acquisitions had a Federal net operating loss carry forward (“NOL”) of approximately $51.7 million. The Federal NOLs, which will expire between 2018 and 2024, are generally available to offset any future taxable income. In general, the Partnership would be deemed to have an “ownership change” under Section 382 if, immediately after any owner shift involving a 5% unitholder or any equity structure shift, the percentage of units of the Partnership owned by one or more 5% 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.

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

Distributions of available cash by us to unitholders 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:

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profitability of operations;

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required principal and interest payments on debt or debt prepayments;

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debt covenants;

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margin account requirements;

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cost of acquisitions;

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issuance of debt and equity securities;

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fluctuations in working capital;

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capital expenditures;

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adjustments in reserves;

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prevailing economic conditions;

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financial, business and other factors;

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increased pension funding requirements;

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the amount of our net operating loss carry forwards (as subject to any Section 382 limitation and utilization); and

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the amount of cash taxes we have to pay in 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 availability of at least $40 million plus 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 35 principal operating locations and 52 depots, 33 of which are owned and 54 of which are leased. As of September 30, 2010, we had a fleet of 990 truck and transport vehicles, the majority of which were owned and 1,097 service vans, the majority of which were leased. We lease our corporate headquarters in Stamford, Connecticut. Our obligations under our credit facility are secured by liens and mortgages on substantially all of the Partnership’s and subsidiaries real and personal property.

ITEM 3.

LEGAL PROCEEDINGS—LITIGATION

We are involved from time to time in litigation incidental to the conduct of our business, but we are not currently a party to any material lawsuit or proceeding.

ITEM 4.

RESERVED

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 and the cash distribution declared on each unit for the fiscal 2010 and 2009 quarters indicated.


	SGU – Common Unit Price Range								Distributions Declared per Unit
	High				Low				Distributions Declared per Unit
	Fiscal Year 2010		Fiscal Year 2009		Fiscal Year 2010		Fiscal Year 2009		Fiscal Year 2010		Fiscal Year 2009
Quarter Ended
December 31,	$	4.17	$	2.40	$	3.55	$	1.83	$	0.0675	$	—
March 31,	$	4.51	$	2.71	$	3.98	$	2.22	$	0.0725	$	0.0675
June 30,	$	4.46	$	3.62	$	4.25	$	2.70	$	0.0725	$	0.0675
September 30,	$	4.74	$	3.71	$	4.32	$	3.26	$	0.0725	$	0.0675

As of September 30, 2010, there were approximately 450 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

According to the terms of our partnership agreement, minimum quarterly distributions on the common units accrue at the rate of $0.0675 per quarter ($0.27 on an annual basis). The information concerning restrictions on distributions required by Item 5. of this report is incorporated by reference to Note 5. Quarterly Distribution of Available Cash, of the Partnership’s consolidated financial statements.

The 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 availability of at least $40 million plus a fixed charge coverage ratio of 1.15x to pay the minimum quarterly distribution of $0.0675 ($0.27 on an annual basis). Any distribution in excess of the minimum quarterly distribution requires the Partnership to have a fixed charge coverage ratio of 1.25x. The Partnership is currently paying a distribution of $0.0725 per quarter ($0.29 annually).

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 (“Plan I”). By the third fiscal quarter of 2010, all 7.5 million common units authorized for repurchase under the Plan I program were repurchased at an average price paid per unit of $4.04 and retired. The Partnership’s repurchase activities took into account SEC safe harbor rules and guidance for issuer repurchases.

On July 19, 2010, the Board of Directors of the Partnership’s General Partner authorized the repurchase of up to 7.0 million of the Partnership’s common units (“Plan II”). The authorized common unit repurchases may be made from time-to-time in the open market, in privately negotiated transactions or in such other manner deemed appropriate by management. In order to facilitate the repurchase program, the Partnership intends to enter into a prearranged unit repurchase plan under Rule 10b5-1 of the Securities Act of 1933, as amended for up to 4.0 million common units with a third party broker. There is no guarantee of the exact number of units that will be purchased under the program and the Partnership may discontinue purchases at any time. The program does not have a time limit. The Partnership’s repurchase activities take into account SEC safe harbor rules and guidance for issuer repurchases. All of the common units purchased in the repurchase program will be retired.

(in thousands, except per unit amounts)


Period	Total Number of Units Purchased as Part of a Publicly Announced Plan or Program		Average Price Paid per Unit (a)		Maximum Number of Units that May Yet Be Purchased Under the Plan II Program
Number of units authorized						7,000
July 2010		—	$	—		7,000
August 2010		1,063	$	4.43		5,937
September 2010		134	$	4.51		5,803

Fourth quarter fiscal year 2010 total		1,197	$	4.44		5,803

(a)	Amounts include repurchase costs.

ITEM 6.

SELECTED HISTORICAL FINANCIAL AND OPERATING DATA

The selected financial data as of September 30, 2010 and 2009, and for the years ended September 30, 2010, 2009 and 2008 is derived from the financial statements of the Partnership included elsewhere in this Report. The selected financial data as of September 30, 2008, 2007 and 2006 and for the years ended September 30, 2007 and 2006 is derived from financial statements of the Partnership not included 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)	2010			2009			2008			2007			2006
Statement of Operations Data:
Sales	$	1,212,776		$	1,206,813		$	1,543,093		$	1,267,175		$	1,296,512
Costs and expenses:
Cost of sales		904,047			875,755			1,257,592			981,559			1,014,565
(Increase) decrease in the fair value of derivative instruments		(5,622	)		(13,690	)		25,467			(15,664	)		45,677
Delivery and branch expenses		218,625			224,478			213,902			199,509			205,454
Depreciation and amortization expenses		15,745			19,406			26,784			28,995			32,415
General and administrative expenses		21,397			20,742			16,043			17,665			21,599

Operating income (loss)		58,584			80,122			3,305			55,111			(23,198	)
Interest expense, net		10,820			13,637			13,808			11,525			21,203
Amortization of debt issuance costs		2,680			2,750			2,339			2,282			2,438
(Gain) loss on redemption of debt		1,132			(9,706	)		—			—			6,603

Income (loss) from continuing operations before income taxes		43,952			73,441			(12,842	)		41,304			(53,442	)
Income tax expense (benefit)		15,632			(57,597	)		566			2,002			477

Income (loss) from continuing operations		28,320			131,038			(13,408	)		39,302			(53,919	)
Loss on sales of discontinued operations, net of income taxes		—			—			—			(1,061	)		—

Income (loss) before cumulative effects of changes in accounting principle for continuing operations		28,320			131,038			(13,408	)		38,241			(53,919	)
Cumulative effects of changes in accounting principles-change in inventory pricing method		—			—			—			—			(344	)

Net income (loss)	$	28,320		$	131,038		$	(13,408	)	$	38,241		$	(54,263	)

Weighted average number of limited partner units:
Basic		70,019			75,738			75,774			75,774			52,944

Diluted		70,019			75,738			75,774			75,774			52,944


	Fiscal Years Ended September 30,
(in thousands, except per unit data)	2010			2009			2008			2007			2006
Per Unit Data:
Basic and diluted income (loss) from continuing operations per unit (a)	$	0.38		$	1.43		$	(0.18	)	$	0.51		$	(1.01	)
Basic and diluted net income (loss) per unit (a)	$	0.38		$	1.43		$	(0.18	)	$	0.50		$	(1.02	)
Cash distribution declared per common unit	$	0.2850		$	0.2025		$	—		$	—		$	—
Balance Sheet Data (end of period):
Current assets	$	246,863		$	376,898		$	344,299		$	320,503		$	295,880
Total assets	$	582,508		$	664,126		$	605,433		$	602,104		$	581,208
Long-term debt	$	82,770		$	133,112		$	173,752		$	173,941		$	174,056
Partners’ Capital	$	279,911		$	306,334		$	199,977		$	216,331		$	173,325
Summary Cash Flow Data:
Net Cash provided by operating activities	$	44,429		$	78,455		$	71,555		$	51,115		$	18,364
Net Cash used in investing activities	$	(73,956	)	$	(7,568	)	$	(5,488	)	$	(29,254	)	$	(3,271	)
Net Cash used in financing activities	$	(104,571	)	$	(54,535	)	$	(145	)	$	(96	)	$	(23,120	)
Other Data:
Earnings from continuing operations before net interest expense, income taxes, depreciation and amortization (EBITDA) (b)	$	73,197		$	109,234		$	30,089		$	84,106		$	2,614
Adjusted EBITDA (b)	$	68,707		$	85,838		$	55,556		$	68,442		$	54,894
Retail gallons sold		307,993			349,385			351,128			376,645			389,920

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

•

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

•

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

•

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

•

our operating performance and return on invested capital 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.

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

•

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

•

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

•

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

•

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

•

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

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


(in thousands)	2010			2009			2008			2007			2006
Income (loss) from continuing operations	$	28,320		$	131,038		$	(13,408	)	$	39,302		$	(53,919	)
Plus:
Income tax expense (benefit)		15,632			(57,597	)		566			2,002			477
Amortization of debt issuance cost		2,680			2,750			2,339			2,282			2,438
Interest expense, net		10,820			13,637			13,808			11,525			21,203
Depreciation and amortization		15,745			19,406			26,784			28,995			32,415

EBITDA from continuing operations		73,197			109,234			30,089			84,106			2,614
(Increase)/decrease in the fair value of derivative instruments		(5,622	)		(13,690	)		25,467			(15,664	)		45,677
(Gain) loss on redemption of debt		1,132			(9,706	)		—			—			6,603

Adjusted EBITDA		68,707			85,838			55,556			68,442			54,894

Add/(subtract)
Income tax (expense) benefit		(15,632	)		57,597			(566	)		(2,002	)		(477	)
Interest expense, net		(10,820	)		(13,637	)		(13,808	)		(11,525	)		(21,203	)
Provision for losses on accounts receivable		5,279			10,310			11,961			5,726			6,105
(Increase) decrease in accounts receivables		(4,570	)		26,657			(28,002	)		5,761			(3,809	)
(Increase) decrease in inventories		(2,012	)		(17,747	)		41,368			(8,222	)		(23,830	)
Increase (decrease) in customer credit balances		(9,250	)		(11,964	)		13,390			(3,724	)		8,576
Change in deferred taxes		13,331			(61,355	)		—			—			—
Change in other operating assets and liabilities		(604	)		2,756			(8,344	)		(3,341	)		(1,892	)

Net cash provided by operating activities	$	44,429		$	78,455		$	71,555		$	51,115		$	18,364

Net Cash used in investing activities	$	(73,956	)	$	(7,568	)	$	(5,488	)	$	(29,254	)	$	(3,271	)

Net Cash used in financing activities	$	(104,571	)	$	(54,535	)	$	(145	)	$	(96	)	$	(23,120	)

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 customers and retain existing customers, our ability to make strategic acquisitions, the impact of litigation, our ability to contract for our current and future supply needs, natural gas conversions, future union relations and the outcome of union negotiations, the impact of current and future governmental regulations, including environmental, health, and safety regulations, the ability to attract and retain employees, customer credit worthiness, counterparty credit worthiness, marketing plans, general economic conditions and new technology. All statements other than statements of historical facts included in this Report including, without limitation, the statements under “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and elsewhere herein, are forward-looking statements. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to be correct and actual results may differ materially from those projected as a result of certain risks and uncertainties. These risks and uncertainties include, but are not limited to, those set forth under the heading “Risk Factors” and “Business 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 our operations and should be read in conjunction with the description of our business and the historical financial and operating data and notes thereto included elsewhere in this document.

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.

Seasonality

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

Degree Day

A “degree day” is an industry measurement of temperature designed to evaluate energy demand and consumption. Degree days are based on how far the average temperature departs from 65°F. Each degree of temperature above 65°F is counted as one cooling degree day, and each degree of temperature below 65°F is counted as one heating degree day. Degree days are accumulated each day over the course of a year and can be compared to a monthly or a long-term (multi-year) average to see if a month or a year was warmer or cooler than usual. Degree days are officially observed by the National Weather Service and officially archived by the National Climatic Data Center. For purposes of evaluating our results of operations, we use the normal heating degree day amount as reported by the National Weather Service in our operating areas.

Weather 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, we have entered into a weather hedge contract with Renaissance Trading Ltd. Under the weather hedge contract we will receive a payment of $35,000 per heating degree-day, when the total number of heating degree-days in the period covered is less than 92.5% of the 10-year average. The hedge covers the period from November 1, 2010 through March 31, 2011 taken as a whole and has a maximum payout of $12.5 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 a ceiling sales price or fixed price for home heating oil over a fixed period of time. When these price-protected customers agree to purchase home heating oil from us for the next heating season, we purchase option contracts, swaps and futures contracts for a substantial majority of the heating oil that we expect to sell to these customers. The amount of home heating oil volume that we hedge per price-protected customer is based upon the estimated fuel consumption per average customer, per month. In the event that the actual usage exceeds the amount of the hedged volume on a monthly basis, we could be required to obtain additional volume at unfavorable margins. In addition, should actual usage in any month be less than the hedged volume, our hedging losses could be greater.

Derivatives

FASB ASC 815-10-05 Derivatives and Hedging topic (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, we have elected not to designate our derivative instruments as hedging instruments under this standard, and, as a result, the changes in fair value of the derivative instruments are recognized in our statement of operations. Therefore, we experience great volatility in earnings as outstanding home heating oil derivative instruments are marked to market and non-cash gains and losses are recorded prior to the sale of the commodity to the customer. To the extent that we continue 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 our overall results. However, we ultimately expect those gains and losses to be offset by the cost of product when purchased.

Impact on Liquidity of Wholesale Product Cost Volatility

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

Income Taxes—Valuation Allowance and Net Operating Loss Carry Forward

At December 31, 2006, we had Federal NOLs of $160.8 million and at December 31, 2009, we had Federal NOLs of $51.7 million. Over this three year period, we utilized $36.4 million of Federal NOLs on average each year to offset our taxable income. We expect that over the next twelve to fifteen months we will utilize substantially all of the remaining unlimited Federal NOLs. After we exhaust the Federal NOLs, the amount of cash taxes that we will pay will increase significantly and will reduce the annual amount of cash available for distribution to unitholders. For example, in calendar 2007, 2008 and 2009 we paid Federal cash taxes of $1.0 million, $0.6 million, and $0.7 million respectively. If we did not have the Federal NOLs available to us for calendar 2007, 2008 and 2009 our Federal cash taxes would have increased to $17.2 million, $11.1 million and $9.9 million for calendar 2007, 2008 and 2009 respectively.

Income Taxes—Book Versus Tax Deductions

Estimated Depreciation and Amortization Expense


(in thousands) Fiscal year	Book		Tax
2011	$	19,586	$	30,835
2012		13,431		27,625
2013		10,224		24,339
2014		8,897		20,493
2015		8,032		17,597

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

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

EBITDA and Adjusted EBITDA (non-GAAP financial measures)

•

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

•

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

•

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

•

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

•

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.

Acquisitions

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 purchased through acquisitions are not included in the calculation of gross customer gains. Marketing activity for our acquisitions from the date that the acquisitions took place is included in the results below. Gross customer losses are the result of a number of factors, including price competition, move-outs, service issues, credit losses and conversion to natural gas. When a customer moves out of an existing home, we count the “move out” as a loss and, if we are successful in signing up the new homeowner, the “move in” is treated as a gain.

Gross Customer Gains, Gross Customer Losses by Quarter and Net Customer Attrition:


	Fiscal Year Ended September
	2010							2009							2008
	Gross Customer				Net			Gross Customer				Net			Gross Customer				Net
	Gains		Losses		Attrition			Gains		Losses		Attrition			Gains		Losses		Attrition
First Quarter		19,000		21,600		(2,600	)		26,300		31,800		(5,500	)		22,000		27,500		(5,500	)
Second Quarter		11,000		14,200		(3,200	)		11,700		24,100		(12,400	)		12,400		19,000		(6,600	)
Third Quarter		5,300		12,600		(7,300	)		5,900		12,300		(6,400	)		8,100		13,700		(5,600	)
Fourth Quarter		10,100		16,800		(6,700	)		10,500		16,500		(6,000	)		18,700		19,300		(600	)

		45,400		65,200		(19,800	)		54,400		84,700		(30,300	)		61,200		79,500		(18,300	)

Gross Customer Gains, Gross Customer Losses and Net Customer Attrition as a Percentage of the Home Heating Oil Customer Base:


	Fiscal Year Ended September
	2010									2009									2008
	Gross Customer						Net			Gross Customer						Net			Gross Customer						Net
	Gains			Losses			Attrition			Gains			Losses			Attrition			Gains			Losses			Attrition
First Quarter		5.1	%		5.8	%		(0.7	%)		6.5	%		7.9	%		(1.4	%)		5.3	%		6.6	%		(1.3	%)
Second Quarter		3.0	%		3.8	%		(0.8	%)		2.9	%		6.0	%		(3.1	%)		3.0	%		4.6	%		(1.6	%)
Third Quarter		1.4	%		3.3	%		(1.9	%)		1.5	%		3.1	%		(1.6	%)		2.0	%		3.3	%		(1.3	%)
Fourth Quarter		2.4	%		3.9	%		(1.6	%)		2.6	%		4.1	%		(1.5	%)		4.5	%		4.6	%		(0.1	%)

		11.9	%		16.8	%		(5.0	%)		13.5	%		21.1	%		(7.6	%)		14.8	%		19.1	%		(4.3	%)

We lost 19,800 accounts (net) during fiscal 2010, or 5.0% of our home heating oil customer base compared to losing 30,300 accounts (net), or 7.6% of our home heating oil customers, in fiscal 2009. Excluding customer gains and losses at the home heating oil operations we acquired in fiscal 2010, which acquisitions were completed after the fall marketing initiatives, we lost 17,600 accounts (net), or 4.7% of our home heating oil customer base. As a result of the extreme price volatility in the summer and fall of 2008, the Partnership was able to take advantage of an unusually high number of consumers seeking an alternate supplier in fiscal 2009, which resulted in an increase in gross customer gains for fiscal 2009. These favorable conditions did not reoccur in fiscal 2010 and gross customer gains were lower. The reduction in gross customer losses of 22,800 accounts was primarily due to the aforementioned market condition, as losses due to price declined by 11,600 accounts. In addition, our credit losses improved by 7,600 accounts and natural gas conversions declined by 1,800. The decline in price losses was largely due to the market conditions described below for fiscal 2009 relating to our fixed price customers and our focus on training and development of our customer service staff.

In fiscal 2009, we lost 30,300 accounts, net, or 7.6% of our home heating oil customer base, as compared to fiscal 2008 in which we lost 18,300 accounts, net, or 4.3 % of our home heating oil customer base. The increase in net losses of 12,000 accounts occurred primarily in the second and fourth quarters of fiscal 2009. In the second quarter of fiscal 2009, our gross customer losses were 24,100, or 5,100 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 price-protected customers decided to renegotiate their agreements with us in fiscal 2009. It is our policy to bill a termination fee when customers cancel 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 cancel their relationship in fiscal 2008 after we billed a termination fee.

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 (14.8% 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 5,200 accounts to 84,700 (21.1% 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 we proactively cancelled for credit increased by 2,400 accounts.

We believe that 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, 2010

Compared to the Fiscal Year Ended September 30, 2009

Volume

For fiscal 2010, retail volume of home heating oil decreased by 41.4 million gallons, or 11.8%, to 308.0 million gallons, as compared to 349.4 million gallons for fiscal 2009. Volume of other petroleum products declined by 0.4 million gallons, or 1.1%, to 39.2 million gallons for fiscal 2010, as compared to 39.6 million gallons for fiscal 2009, as the additional volume from acquisitions offset a decline in the base business. 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
Volume—Fiscal 2009		349.4
Impact of warmer temperatures		(31.7	)
Net customer attrition—residential / commercial		(12.5	)
Acquisitions		3.7
Other		(0.9	)

Change		(41.4	)

Volume—Fiscal 2010		308.0

Temperatures in our geographic areas of operations for fiscal 2010 were 9.1% warmer than fiscal 2009 and 7.9% warmer than normal, as reported by the National Oceanic Administration (“NOAA”). For fiscal 2010, net customer attrition excluding acquisitions, which were completed after the heating season, was 4.7%. (The impact on volume from our acquisitions is reported separately.) 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.

The percentage of home heating oil volume sold to residential variable price customers increased to 42.0% of total home heating oil volume sales for fiscal 2010, as compared to 40.1% for fiscal 2009. Accordingly, the percentage of home heating oil volume sold to residential price-protected customers decreased to 44.1% for fiscal 2010, as compared to 45.5% for fiscal 2009. For fiscal 2010, sales to commercial/industrial customers represented 13.8% of total home heating oil volume sales, as compared to 14.3% for fiscal 2009.

Product Sales

For fiscal 2010, product sales decreased $5.0 million, or 0.4%, to $1.028 billion, as compared to $1.033 billion for fiscal 2009, as an 11.0% increase in home heating oil selling prices and an increase in sales of other petroleum products of $15.9 million (1.5% of total product sales) was reduced by a 11.8% decrease in home heating oil volume. Selling prices rose largely due to an increase in wholesale product costs.

Installation and Service Sales

For fiscal 2010, installation and service sales increased $10.4 million, or 5.9%, to $184.4 million, as compared to $174.0 million for fiscal 2009, as the additional service and installation revenue from acquisitions of $6.9 million and higher air conditioning installation and service revenue of $5.4 million was offset slightly by a $1.1 million reduction in heating installations and a fall in service contract revenue due to net customer attrition and competitive pressures. The Partnership believes that the mild spring and relatively warm summer weather in fiscal 2010 in the areas in which the Partnership operates were the main drivers of the increase in air conditioning related revenues while the warm winter adversely impacted heating installations.

Cost of Product

For fiscal 2010, cost of product increased $26.4 million, or 3.7%, to $734.6 million, as compared to $708.2 million for fiscal 2009, as the impact of increases in home heating oil and other petroleum products was reduced by the 11.8% decline in home heating oil volume.

Gross Profit Product

The table below recalculates the Partnership’s per gallon margins and reconciles product gross profit for home heating oil and other petroleum products. We believe the change in home heating oil margins should be evaluated before the effects of increases or decreases in the fair value of derivative instruments, as we believe that realized per gallon margins should not include the impact of non-cash changes in the market value of hedges before the settlement of the underlying transaction. On that basis, home heating oil margins for fiscal 2010 increased by $0.0201 per gallon, or 2.2%, to $0.9136 per gallon, from $0.8935 per gallon in fiscal 2009. Product sales and cost of product include home heating oil, other petroleum products and liquidated damages billings.


	Fiscal Year End
(In millions, except per gallon amounts)	September 30, 2010				September 30, 2009
	Amount		Per Gallon		Amount		Per Gallon
Home Heating Oil
Volume		308.0				349.4

Sales	$	934.2	$	3.0331	$	954.5	$	2.7318
Cost	$	652.8	$	2.1195	$	642.3	$	1.8383

Gross Profit	$	281.4	$	0.9136	$	312.2	$	0.8935


	Amount		Per Gallon		Amount		Per Gallon
Other Petroleum Products
Volume		39.2				39.6

Sales	$	94.2	$	2.4064	$	78.4	$	1.9785
Cost	$	81.8	$	2.0885	$	65.9	$	1.6640

Gross Profit	$	12.4	$	0.3179	$	12.5	$	0.3145


	Amount				Amount
Total Product
Sales	$	1,028.4			$	1,032.8
Cost	$	734.6			$	708.2

Gross Profit	$	293.8			$	324.6

For fiscal 2010, total product gross profit decreased by $30.8 million to $293.8 million, as compared to $324.6 million for fiscal 2009, as the impact of higher home heating oil per gallon margins ($6.2 million) was more than offset by the impact of lower home heating oil volume ($37.0 million.) In fiscal 2010, gross profit from other petroleum products equaled fiscal 2009 and per gallon margins increased slightly.

Cost of Installations and Service

For fiscal 2010, cost of installations and service increased $1.9 million, or 1.1%, to $169.5 million, as compared to $167.6 million for fiscal 2009, reflecting additional expense from acquisitions of $5.6 million, which was partially offset by lower vehicle fuel costs of $3.5 million.

The gross profit realized from service (including installations) increased by $8.5 million, from $6.4 million for fiscal 2009 to $14.9 million for fiscal 2010. Management views the service and installation department on a combined basis because many expenses cannot be separated or allocated to either service or installation billings. Many overhead functions and direct expenses such as service technician time cannot be precisely allocated.

Installation costs were $55.8 million, or 85.4% of installation sales during fiscal 2010, and were $52.9 million, or 88.5% of installation sales during fiscal 2009. The decline in installation costs as a percentage of sales was largely the result of reduced staffing levels as the Partnership responded to the impact on installation sales of the economic downturn of the last several years. In fiscal 2009, the Partnership did not reduce staffing levels as quickly as the decline in installation revenue. Service expenses decreased to $113.7 million, or 95.5% of service sales during fiscal 2010, from $114.7 million in fiscal 2009, or 100.4% of sales. The decrease in

service expenses of $1.0 million was largely due to the $3.5 million decline in vehicle fuel costs partially offset by additional service costs associated with acquisitions of $3.2 million. The decline in service costs as a percentage of service revenue was due to higher profitability of the increased air conditioning service and the decline in vehicle fuels.

(Increase) Decrease in the Fair Value of Derivative Instruments

During fiscal 2010, the change in the fair value of derivative instruments resulted in the recording of a $5.6 million increase due to the expiration of certain hedged positions ($9.2 million increase), and a decrease in market value for unexpired hedges ($3.5 million charge).

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

Delivery and Branch Expenses

For fiscal 2010, delivery and branch expenses decreased $5.9 million, or 2.6%, to $218.6 million, as compared to $224.5 million in fiscal 2009. While acquisitions resulted in an increase in delivery and branch expenses of $8.4 million, delivery and branch expenses in the Partnership’s base business declined by $14.3 million. Account losses due to poor credit declined by 47.5% which led a decline in bad debt expense of $5.3 million and vehicle fuel expenses fell by $3.6 million largely due to a decline in fuel costs. Delivery and branch expenses were reduced by $4.5 million due to the decline in home heating oil volume which mitigated the impact of inflationary pressures on operating expenses. On a cents per gallon basis, delivery and branch expenses increased 6.7 cents per gallon or 10.5%, from 64.3 cents for fiscal 2009 to 71.0 cents for fiscal 2010 due to the fixed nature of certain operating expenses that could not be adjusted due to the 11.8% decline in home heating oil volume. Our fiscal 2010 acquisitions, which were completed after the heating season, resulted in the Partnership having to incur operating costs for such acquisitions without any heating season volume being generated by them which adversely impacted the year over year operating cost comparison by 1.9 cents per gallon.

Depreciation and Amortization

For fiscal 2010, depreciation and amortization expenses were $15.7 million, as compared to $19.4 million for fiscal 2009. Amortization expense was lower by $3.5 million, as the customer list of acquisitions from fiscal 2002 with 7 year lives and acquisitions from 1999 with 10 year lives became fully amortized in fiscal 2009 partially offset by increased amortization expense from fiscal 2010 acquisitions having 7 and 10 year lives.

General and Administrative Expenses

For fiscal 2010, general and administrative expenses increased $0.7 million to $21.4 million, as compared to $20.7 million for fiscal 2009. Legal and professional expenses relating to acquisitions were $0.7 million in fiscal 2010 and pension expense relating to the Partnership’s frozen pension plan increased by $0.9 million to $3.1 million. Generally, a higher contribution to the frozen pension plan was required to offset lower than expected assets returns. In fiscal 2010, Adjusted EBITDA for profit sharing calculation purposes decreased resulting in a corresponding decrease in profit sharing expense of $0.5 million.

The Partnership accrues approximately 6% of Adjusted EBITDA as defined in the profit sharing plan for distribution to its employees, and this amount is payable when the Partnership achieves actual adjusted EBITDA of at least 70% of the amount budgeted. If Adjusted EBITDA increases, the dollar amount of the profit sharing pool will increase. On the other hand, if Adjusted EBITDA decreases, the dollar amount of the profit sharing pool will be reduced.

Interest Expense

For fiscal 2010, interest expense decreased by $3.5 million, or 19.7 % to $14.3 million, as compared to $17.8 million for fiscal 2009. Over the last two fiscal years, the Partnership has repurchased $90.3 million face value of its 10.25% Senior Notes lowering the average long-term debt outstanding for these Notes by $44.7 million and the corresponding interest expense by $4.5 million. Bank charges increased by $1.0 million largely due to an increase in letter of credit fees.

On November 16, 2010, the Partnership sold $125.0 million 8.875% Senior Notes due 2017 at a price of 99.35%. The proceeds will be used to repurchase $82.5 million of Senior Notes due February 2013. As a result, the Partnership expects that interest expense will increase in fiscal 2011.

During fiscal 2010, average bank borrowings were $3.6 million and the corresponding interest expense increased by $0.2 million. There were no bank borrowings in fiscal 2009.

Interest Income

For fiscal 2010, interest income decreased $0.7 million to $3.5 million, as compared to $4.2 million for fiscal 2009, due to lower invested cash balances and lower finance charge income on past due accounts receivables balances.

Amortization of Debt Issuance Costs

For fiscal 2010, amortization of debt issuance costs decreased slightly to $2.7 million, as compared to $2.8 million in fiscal 2009.

Gain (loss) on Bond Repurchase

During fiscal 2010, the Partnership repurchased $50.0 million face value of its 10.25% Senior Notes due February 2013 at an average price of $101.7 per $100 of principal plus accrued interest. The Partnership recorded a loss of $1.1 million for this transaction.

During fiscal 2009, the Partnership repurchased $40.3 million face value of its 10.25% Senior Notes due February 2013 at an average price of $75.1 per $100 of principal plus accrued interest. The Partnership recorded a gain of $9.7 million.

Income Tax Expense (Benefit)

Income tax expense increased by $73.2 million in fiscal 2010 as compared to fiscal 2009 primarily due to 2010 having $82.5 million in lower benefit from the release of opening valuation allowance than in 2009. Based on a number of factors, including historical operating performance and our expectation that we could generate enough sustainable taxable income for the foreseeable future in the jurisdictions for which the opening valuation allowance was established, we concluded at the end of fiscal 2010 that these deferred tax assets should be recognized. For fiscal 2009 this benefit was $86.4, representing the majority of our opening valuation allowance in that year.

This decreased benefit of $82.5 million was offset in fiscal 2010 by $7.8 million in lower deferred tax expense and $1.5 million in lower current tax expense as compared to fiscal 2009. These lower tax expenses were primarily due to fiscal 2010 having $29.5 million in lower income before income taxes than fiscal 2009. Our effective tax rate for fiscal 2010 of 35.6% includes the impact of the release of the opening valuation allowance which reduced the effective tax rate by 8.9%.

Going forward, 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 for the current period. The deferred tax expense represents the amount of income taxes that we would have paid if we did not have the benefit of our net loss carry forwards and other deferred tax assets. We expect that we will utilize substantially all of our unlimited net Federal operating loss carryforward by the next twelve to fifteen months.

Net Income (Loss)

For fiscal 2010, net income of $28.3 million was recorded, as compared to a net income of $131.0 million for fiscal 2009. This decrease of $102.7 million was primarily due to the recording of an $86.4 million income tax benefit in fiscal 2009 from the release of the majority of the Partnership’s opening valuation allowance. In fiscal 2010, only $3.9 million of opening valuation allowance was released. In addition, the after tax impact of lower earnings reduced net income by $17.9 million.

Adjusted EBITDA

For fiscal 2010, Adjusted EBITDA decreased by $17.1 million to $68.7 million, as compared to $85.8 million for fiscal 2009, as the impact of a decline in home heating oil volume and a $3.6 million Adjusted EBITDA loss from acquisitions more than offset an improvement in net service and installation profitability, an increase in home heating oil per gallon margins and lower operating expense. The Adjusted EBITDA loss from fiscal 2010 acquisitions was expected as these assets were purchased subsequent to the heating season.

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)	2010			2009
Income from continuing operations	$	28,320		$	131,038
Plus:
Income tax expense (benefit)		15,632			(57,597	)
Amortization of debt issuance cost		2,680			2,750
Interest expense, net		10,820			13,637
Depreciation and amortization		15,745			19,406

EBITDA (a) from continuing operations		73,197			109,234
(Increase) / decrease in the fair value of derivative instruments		(5,622	)		(13,690	)
(Gain) loss on redemption of debt		1,132			(9,706	)

Adjusted EBITDA (a)		68,707			85,838

Add / (subtract)
Income tax (expense) benefit		(15,632	)		57,597
Interest expense, net		(10,820	)		(13,637	)
Provision for losses on accounts receivable		5,279			10,310
(Increase) decrease in accounts receivables		(4,570	)		26,657
Increase in inventories		(2,012	)		(17,747	)
Decrease in customer credit balances		(9,250	)		(11,964	)
Change in deferred taxes		13,331			(61,355	)
Change in other operating assets and liabilities		(604	)		2,756

Net cash provided by (used in) operating activities	$	44,429		$	78,455

Net cash used in investing activities	$	(73,956	)	$	(7,568	)

Net cash used in financing activities	$	(104,571	)	$	(54,535	)

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

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

Fiscal Year Ended September 30, 2009

Compared to the Fiscal Year Ended September 30, 2008

Volume

For fiscal 2009, retail volume of home heating oil decreased by 1.7 million gallons, or 0.5%, to 349.4 million gallons, as compared to 351.1 million gallons for fiscal 2008. Volume of other petroleum products declined by 9.3 million gallons, or 19.0%, to 39.6 million gallons for fiscal 2009, as compared to 48.9 million gallons for fiscal 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
Volume—Fiscal 2008		351.1
Impact of colder temperatures		28.4
Net customer attrition—retail and commercial		(28.7	)
Acquisitions		6.1
Conservation/Other		(7.5	)

Change		(1.7	)

Volume—Fiscal 2009		349.4

Temperatures in our geographic areas of operations for fiscal 2009 were 8.1% colder than fiscal 2008 and 1.3% colder than normal, as reported by the National Oceanic 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 and this decrease is reflected in the “Conservation/Other” heading in the above table.

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 2009, product sales decreased $321.1 million, or 23.7%, to $1.033 billion, as compared to $1.354 billion for fiscal 2008, due to a 20.0% decrease in home heating oil selling prices, a 0.5% decrease in home heating oil volume, and a decline in sales of other petroleum products of $76.9 million.

Installation and Service Sales

For fiscal 2009, installation and service sales decreased $15.1 million, or 8.0%, to $174.0 million, as compared to $189.1 million for fiscal 2008, as a decline in installation sales of $15.2 million was reduced by a slight increase in service revenue of $0.1 million. We believe that rising unemployment, reduced home equity loans and consumer credit, and reduced consumer confidence led to a decline in the demand for new heating systems ($8.3 million), air conditioning equipment ($2.2 million), as well as new construction plumbing installations ($4.5 million). The cool spring also adversely impacted the demand for new and replacement air conditioning systems over the summer months. While service contract revenue increased by $2.2 million, revenue from non-essential services, which include plumbing and air conditioning service, declined $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 2009, cost of product decreased $373.8 million, or 34.5%, to $708.2 million, as compared to $1.082 billion for fiscal 2008, due largely to a decline in the wholesale product cost for home heating oil and other petroleum products. The 0.5% decline in home heating oil volume sold and the 19.0% decline in other petroleum products sold also contributed to the decline in cost of product.

Gross Profit Product

The table below recalculates the Partnership’s per gallon margins and reconciles product gross profit for home heating oil and other petroleum products. We believe the change in home heating oil margins should be evaluated before the effects of increases or decreases in the fair value of derivative instruments, as we believe that realized per gallon margins should not include the impact of non-cash changes in the market value of hedges before the settlement of the underlying transaction. On that basis, home heating oil margins for fiscal 2009 increased by $0.1522 per gallon, or 20.5%, to $0.8935 per gallon, from $0.7413 per gallon in fiscal 2008. Product sales and cost of product include home heating oil, other petroleum products and liquidated damages billings.

For fiscal 2009, total product gross profit increased by $52.5 million to $324.6 million, as compared to $272.1 million for fiscal 2008, as the impact of higher home heating oil per gallon margins ($53.2 million) and an increase in gross profit from other petroleum products ($0.6 million) was reduced by the impact of lower home heating oil volume ($1.3 million).


	Fiscal Year Ended
(In millions, except per gallon amounts)	September 30, 2009				September 30, 2008
	Amount		Per Gallon		Amount		Per Gallon
Home Heating Oil
Volume		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		Per Gallon		Amount		Per Gallon
Other Petroleum Products
Volume		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				Amount		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

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 2009, cost of installations and service decreased $8.2 million, or 4.7%, to $167.6 million, as compared to $175.8 million for fiscal 2008, as a decrease in installation costs of $11.6 million was partially offset by higher service expenses of $3.4 million. Installation costs were lower, largely due to the corresponding decrease in installation sales as described above. Service expenses were higher due to an increase in vehicle fuel costs of $2.1 million, as the Partnership hedged a portion of its vehicle fuel costs during a higher cost period. For fiscal 2010, the Partnership has again hedged its vehicle fuel costs, which should lower this expense by approximately $2.3 million in fiscal 2010. Colder than normal winter temperatures also increased the operating expense of the service department due to the increased need to service our customer’s heating equipment. The gross profit realized from service (including installations) decreased by $7.0 million, from $13.4 million for fiscal 2008 to $6.4 million for fiscal 2009 due to the decline in installation sales and the increase in vehicle fuel costs. Installation costs were $53.0 million, or 88.6% of installation sales during fiscal 2009, and were $64.5 million, or 86.0% of installation sales during fiscal 2008. Installation costs as a percentage of installation sales increased due to the fixed nature of certain installation costs.

Service expenses increased to $114.7 million, or 100.4% of service sales, during fiscal 2009, from $111.3 million in fiscal 2008, or 97.5% of service sales. Service costs as a percentage of total service revenue increased due to the rise in vehicle fuel costs and, the impact on service costs of colder temperatures. In addition, the Partnership was not able to fully reduce its service expenses in response to unforeseen reductions in non-essential service billings such as air conditioning and plumbing services, which also contributed to the increase in the percentage of service expense to service revenues.

(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 $10.6 million, or 5.0%, to $224.5 million, as compared to $213.9 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 3.33 cents per gallon, or 5.5%, from $0.6092 cents per gallon for fiscal 2008, to $0.6425 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 2009, depreciation and amortization expenses were $19.4 million, as compared to $26.8 million for fiscal 2008. Amortization expense was lower by $6.3 million, as acquisitions from fiscal 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 capital expenditures for technology acquired in fiscal 2003 became fully depreciated.

General and Administrative Expenses

For fiscal 2009, general and administrative expenses increased $4.7 million, or 29.4%, to $20.7 million, as compared to $16.0 million for fiscal 2008, largely due to higher compensation expense of $2.1 million relating to the Partnership’s profit sharing plan and an increase in pension expense of $1.6 million largely due to the decline in the assets of the Partnership’s frozen defined benefit pension plan. The balance of the increase, or $1.0 million, was due to wage increases and higher legal and professional expenses. The Partnership accrues approximately 6% of Adjusted EBITDA as defined in the profit sharing plan for distribution to its employees and is payable when the Partnership achieves actual adjusted EBITDA of at least 70% of the amount budgeted. In fiscal 2009, adjusted EBITDA increased by $30.3 million to $85.8 million, which drove the increase in profit sharing expense. If Adjusted EBITDA increases, the dollar amount of the profit sharing pool will increase. On the other hand, if Adjusted EBITDA decreases, the dollar amount of the profit sharing pool will be less.

Operating Income

For fiscal 2009, operating income increased $76.8 million to $80.1 million, as compared to $3.3 million for fiscal 2008 as a net positive change in the fair value of derivative instruments of $39.2 million and an increase in product gross profit of $52.5 million was reduced by lower installation and service profitability totaling $7.0 million and an increase in operating expenses of $7.9 million (including depreciation and amortization).

Interest Expense

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 2009, interest income decreased $2.7 million to $4.2 million, as compared to $6.9 million for fiscal 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 2009, amortization of debt issuance costs increased to $2.8 million, as compared to fiscal 2008 of $2.3 million largely due to the accelerated amortization of fees related to the revolving credit facility that was amended in July 2009.

Gains on Bond Repurchase

During fiscal 2009, the Partnership repurchased $40.3 million face value of its 10.25% Senior Notes due February 2013 at an average price of $75.10 per $100 of principal plus accrued interest. The Partnership recorded a gain of $9.7 million for these transactions.

Income Tax Expense (Benefit)

For fiscal 2009, an income tax benefit of $86.4 million was recorded for the release of a majority of our opening valuation allowance. This benefit was offset by a current income tax expense of $3.8 million and a deferred income tax expense of $25.0 million related to current year activity, resulting in a net income tax benefit of $57.6 million, as compared to income tax expense of $0.6 million for fiscal 2008. Based 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 740-10-05 Income Taxes topic (SFAS No. 109), we recorded a tax benefit during fiscal 2009 releasing a majority of the remaining valuation allowance, resulting in a non-cash increase in net income of $86.4 million.

For the next 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 tax that we would have paid if we do not have the benefit of our net loss carry forwards and other deferred tax assets.

Net Income (Loss)

For fiscal 2009, net income of $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.

Adjusted EBITDA

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.


	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 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	)

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

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

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 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, 2010 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

Due to the seasonal nature of the home heating oil business, cash is generally used in operations during the winter (our first and second fiscal quarters) as customers receive deliveries and pay for products purchased within our payment terms, and cash is generally provided by operating activities during the spring and summer (our third and fourth quarters) when customer payments exceed deliveries.

During fiscal 2010, cash provided by operating activities declined by $34.1 million to $44.4 million, as compared to $78.5 million for fiscal 2009 as favorable changes in cash used for inventory purchases of $15.7 million and option purchases of $12.2 million were more than offset by a decline in cash generated from operations of $17.9 million, increases in cash used to finance accounts receivable of $31.2 million and higher pension plan contributions of $11.2 million. During fiscal 2010, the Partnership bought 23.9 million fewer gallons of home heating oil for inventory than during fiscal 2009, which resulted in a favorable change in cash flows of $15.7 million. At the beginning of fiscal 2009, the Partnership’s physical inventory of home heating oil was comparatively low because the Partnership did not prebuy physical inventory due to the relatively high cost at the time. The change in inventory was also impacted by price. During fiscal 2010, inventory costs increased by $0.42 per gallon as compared to the prior period which experienced a reduction in inventory cost of $1.54 per gallon. In fiscal 2010, the Partnership structured its option purchases such that the cost of the option will be paid as it expires rather than at the time the hedge is entered into. This favorably impacted cash in fiscal 2010. Cash flow from operations declined by $17.9 million largely due to the weather related decline in home heating oil volume and operating loss from acquisitions completed after the heating oil season. The Partnerships’ accounts receivables increased by $4.6 million during fiscal 2010 which compares to fiscal 2009 when accounts receivable decreased by $26.7 million. In fiscal 2010, home heating oil prices rose from the beginning of the year which drove a slight increase in accounts receivable as compared to fiscal 2009 when selling prices were much lower than the beginning of the fiscal year. Day’s sales outstanding were 50 days as of September 30, 2010 as compared to 50 days as of September 30, 2009 and 57 days as of September 30, 2008. In addition, during fiscal 2010 the Partnership contributed $13.1 million into the frozen pension plan which exceeded the fiscal 2009 contribution of $1.9 million by $11.2 million.

During fiscal 2009, we generated $78.5 million in cash flow from operating activities, which was $6.9 million higher than the $71.6 million of cash provided by operations for fiscal 2008. This improvement was primarily due to the impact of lower wholesale product costs, which impacts accounts receivable collections, inventory costs, prepaid hedging costs, hedging margin requirements, customer credit balances, accounts payable and accrued expenses. Our cash flow from operations for fiscal 2009 also benefited from higher earnings from operations, when compared to fiscal 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 38% 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.

Investing Activities

During fiscal 2010, we spent $5.6 million for fixed assets and received $0.4 million from the sale of fixed assets, as we invested in computer hardware and software ($1.9 million), refurbished certain physical plants ($1.2 million) and made additions to our fleet and other equipment ($2.5 million). We completed five acquisitions with a total cash outlay of $68.8 million (including $4.2 million in working capital) and allocated $64.1 million of the gross purchase to intangible assets, $7.6 million to fixed assets and $2.9 million to other net liabilities.

During fiscal 2009, our capital expenditures totaled $4.3 million, as we invested in computer hardware and software ($1.4 million), refurbished certain physical plants ($1.0 million) and made additions to our fleet and other equipment ($1.9 million). We also completed one acquisition for $4.0 million and allocated $3.4 million of the gross purchase to intangible assets and $0.6 million to fleet. We paid $ 3.4 million in cash 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.

Financing Activities

During fiscal 2010, the Partnership repurchased 8.1 million common units for $33.2 million in connection with the unit repurchase plan program and paid distributions to the unit holders of $20.4 million. Also during fiscal 2010, we borrowed and repaid $36.8 million under our revolving credit facility. In February 2010, the Partnership redeemed $50.0 million face value of its outstanding 10.25% Senior Notes due in 2013 at a price equal to 101.708% of face value.

During fiscal 2009, the Partnership repurchased $40.3 million face value of its 10.25% Senior Notes due February 2013 for $30.2 million and paid distributions to our unitholders of $15.4 million. During fiscal 2009, we did not borrow under our revolving credit facility but had letters-of-credit outstanding under the facility. We also paid $6.6 million in fees for our new credit agreement and spent $2.3 million to purchase 637,285 common units in connection with our unit repurchase plan program.

For fiscal 2008, we borrowed and repaid $57.2 million under our revolving credit facility.

FINANCING AND SOURCES OF LIQUIDITY

Liquidity and Capital Resources

Our ability to satisfy our financial obligations depends on our future performance, which will be subject to prevailing economic, financial, business and weather conditions, the ability to pass on the full impact of high wholesale heating oil prices to customers, the effects of high net customer attrition, conservation and other economic and geo-political factors, most of which are beyond our control. In the near term, capital requirements are expected to be provided by cash flows from operating activities, cash on hand at September 30, 2010, the $36.8 million in net cash raised from our November 2010 debt offering 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 a our revolving credit facility.

In July 2009, we entered into an amended and restated asset based revolving credit facility with a group of lenders, that expires in July, 2012 and which provides us with the ability to borrow up to $240 million ($290 million during the heating season from November through April of each year) for working capital purposes (subject to certain borrowing base limitations and coverage ratios), including the issuance of up to $100.0 million in letters of credit. The Partnership can increase the facility size by $50 million without the consent of the bank group. However, the bank group is not obligated to fund the $50 million increase. If the bank group elects not to fund the increase, the Partnership can add additional lenders to the group, with the consent of the Agent, which shall not

be unreasonably withheld. Obligations under the new revolving credit facility are secured by liens on substantially all of our assets including accounts receivable, inventory, general intangibles, real property, fixtures and equipment. During this past heating season, we did not borrow under our previous credit facility. As of September 30, 2010, $42.3 million in letters of credit were outstanding, of which $42.0 million are for current and future insurance reserves and bonds and $0.3 million are for seasonal inventory purchases and other working capital purposes. We have reduced our reliance on letters of credit for inventory purposes as we have increased our trade credit to over $58.8 million.

Under the terms of the credit facility, we must maintain at all times either availability (borrowing base less amounts borrowed and letters of credit issued) of $43.5 million (15% of the maximum facility size) or a fixed charge coverage ratio (as defined in the credit agreement) of not less than 1.1x. As of September 30, 2010, availability, as defined in the amended and restated credit agreement, was $104.8 million 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 comply with these covenants it could have a material adverse effect on the Partnership’s liquidity and results of its operations.

On November 16, 2010, the Partnership sold $125.0 million 8.875% Senior Notes due 2017 at a price of 99.35%. A portion of the net proceeds will be used on December 20, 2010, to repurchase $82.5 million of 10.25% Senior Notes due February 2013. After paying expenses of $3.5 million and a call premium of $1.4 million, the Partnership’s cash balance increased by $36.8 million, which can be utilized for general partnership purposes.

The Partnership’s scheduled interest payments for fiscal 2011 are $8.9 million on its Senior Notes and annual maintenance capital expenditures for fixed assets are estimated to be approximately $5.0 to $7.0 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 a total of approximately $10.0 million over the next five fiscal years. We anticipate paying distributions of approximately $19.5 million in fiscal 2011 and we will continue to purchase common units as authorized under our unit repurchase plan. In addition, we will continue to seek strategic acquisitions.

Partnership Distribution Provisions

Commencing with the fiscal quarter ended December 31, 2008, we are required to make distributions in an amount equal to our Available Cash, as defined in our Partnership Agreement, no more than 45 days after the end of each fiscal quarter, to holders of record on the applicable record dates. Available Cash, as defined in our Partnership Agreement, generally means all cash on hand at the end of the relevant fiscal quarter less the amount of cash reserves established by the Board of Directors of our general partner in its reasonable discretion for future cash requirements. These reserves are established for the proper conduct of our business, including acquisitions, the payment of debt principal and interest and for distributions during the next four quarters and to comply with applicable laws and the terms of any debt agreements or other agreements to which we are subject. Under the terms of our credit facility, the Partnership must maintain availability of at least $40 million plus 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 26, 2010, we declared a quarterly distribution of $0.0725 per unit, or $0.29 per unit on an annualized basis, on all common units in respect of the fourth quarter of fiscal 2010 payable on November 12, 2010 to holders of record on November 4, 2010. 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 Partnership had no capital lease obligations as of September 30, 2010.

Reserves for income taxes under FASB ASC 740-10-05 Income Taxes Topic (“FIN 48”) are not included in the table because we cannot reasonably predict the ultimate timing of settlement of our reserves for income taxes with the respective taxing authorities.

The table below summarizes the payment schedule of our contractual obligations at September 30, 2010 (in thousands):


	Payments Due by Fiscal Year
	Total		2011		2012 and 2013		2014 and 2015		Thereafter
Long-term debt obligations (a)	$	82,499	$	—	$	82,499	$	—	$	—
Operating lease obligations (b)		55,979		10,541		19,241		14,413		11,784
Purchase obligations (c)		16,609		9,777		6,742		90		—
Interest obligations (d)		23,890		9,956		13,934		—		—
Long-term liabilities reflected on the balance sheet (e)		4,425		350		700		700		2,675

	$	183,402	$	30,624	$	123,116	$	15,203	$	14,459

(a)	On November 16, 2010, the Partnership sold $125.0 million 8.875% Senior Notes due 2017 at a price of 99.35%. The proceeds will be used to repurchase $82.5 million of Senior Notes due February 2013.

(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, 2010 for operations such as customer related invoice and statement processing and voice and data phone/computer services.

(d)	Reflects 10.25% interest obligations on our $82.5 million senior notes (excluding discounts and premiums) due February 2013 and the unused commitment fee on the revolving credit facility.

(e)

Reflects long-term liabilities excluding a pension accrual of approximately $16.6 million. Under current prescribed regulatory minimum funding requirements, we have satisfied the minimum funding obligations related to our pension plans for fiscal 2010 and we estimate minimum cash contributions of $3.2 million, $2.3 million, $2.0 million, $2.0 million and $0.4 million, for fiscal 2011, 2012, 2013, 2014 and 2015 respectively.

Recent Accounting Pronouncements

In fiscal 2010, the Partnership adopted the revised provisions of FASB ASC 805-10 Business Combinations. 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.

In July 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2010-20 Receivables (Topic 310): Disclosures about the Credit Quality of Financing Receivables and the Allowance for Credit Losses. This standard requires companies to improve their disclosures about the credit quality of their financing receivables and the credit reserves held against them. The guidance covers trade accounts receivables, financing receivables, loans, loan syndications, factoring arrangements, and standby letters of credit. The Partnership is required to adopt this standard in the first quarter of fiscal 2011. The Partnership is currently assessing the impact of the disclosure requirements.

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 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 twenty 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, 2010, we had $58.9 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 2010 would have increased by approximately $0.4 million.

FASB ASC 350-10-05 Intangibles-Goodwill and Other topic 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, 2010, we had $199.1 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. It was determined based on this analysis that there was no goodwill impairment as of August 31, 2010. The preparation of this analysis was based upon management’s estimates and assumptions, and future impairment calculations would be affected by actual results that are materially different from projected amounts. To provide for a sensitivity of the discount rates and transaction multiples used, ranges of high and low values are employed in the analysis, with the low values examined to ensure that a reasonably likely change in an assumption would not cause the Partnership to reach a different conclusion.

Although the Partnership believes that its projections reflect its best estimates of future performance, changes in estimated revenues, per gallon margins or discount rates may have an impact on the estimated fair value. Any increase in estimated cash flows or a decrease in the discount rate would not have an impact on the carrying value of the goodwill. A decrease in future estimated cash flows or an increase in the discount rate could require the Partnership to determine whether the recognition of a goodwill impairment charge would be required.

The Partnership estimates 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 Income Approach uses management’s projections of cash flows, market trends and other factors to determine the value of the reporting unit based on discounted cash flows. The Partnership’s discount rate was calculated based on the weighted average cost of capital, using inputs of comparable companies in the same industry. The Partnership’s conclusion of the fair value of the reporting unit was supported based on a sensitivity analysis performed using a range of discount rates and terminal multiples.

The 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.

In addition, the Partnership performs a reasonableness check of its concluded value for its sole reporting unit by reconciling the results of the goodwill analysis with its market capitalization.

Depreciation of Property 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 and equipment was $44.7 million at September 30, 2010. 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 2010 would have increased by approximately $1.0 million.

Fair Values of Derivatives

FASB ASC 815-10-05 Derivatives and Hedging topic, established accounting and reporting standards requiring that derivative instruments be recorded at fair value and included in the consolidated balance sheet as assets or liabilities. To the extent derivative instruments designated as cash flow hedges are effective 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

FASB ASC 715-10-05 Compensation-Retirement Benefits topic, requires an employer to (i) measure the funded status of a defined benefit postretirement plan as of the date of its fiscal year-end statement of financial position, (ii) to recognize the overfunded or underfunded status of this plan as an asset or liability in its statement of financial position and (iii) to recognize changes in that funded status in the year which the changes occur through comprehensive income.

This standard requires the Partnership to make assumptions as to the expected long-term rate of return that could be achieved on defined benefit plan assets and discount rates to determine the present value of the plans’ pension obligations. The Partnership evaluates these critical assumptions at least annually.

The discount rate enables the Partnership to state expected future cash flows at a present value on the measurement date. The rate is required to represent the market rate for high-quality fixed income investments. A lower discount rate increases the present value of benefit obligations and increases pension expense in the following fiscal year. A 25 basis point decrease in the discount rated used for fiscal 2010 would have increased pension expense by approximately $0.1 million and would have increased the pension liability by another $1.6 million. The discount rate used to determine net periodic pension expense was 5.4% in 2010, 7.6% in 2009, and 6.2% in 2008. The discount rate used in determining end of year pension obligations was 4.7% in 2010, 5.4% in 2009, and 7.6% in 2008. 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.

We consider the current and expected asset allocations, as well as historical and expected returns on various categories of plan assets to determine our expected long-term rate of return on pension plan assets. The expected long-term rate of return on assets is developed with input from the Partnership’s qualified actuaries. The long-term rate of return assumption used for determining net periodic pension expense for fiscal 2010 and 2009 was 7.75% and 8.25% respectively. A further 25 basis point decrease in the expected return on assets would have increased pension expense in fiscal 2010 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, 2010, $33.2 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, we establish an allowance for doubtful accounts, representing the Partnership’s best estimate of amounts that may not be collectible. Actual losses could differ from management’s estimates.

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, 2010, we had approximately $37.4 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.

At September 30, 2010, we had outstanding borrowings totaling $82.5 million (excluding discounts and premiums), none of which is subject to variable interest rates.

We regularly 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, 2010, the potential impact on our hedging activity would be to increase the fair market value of these outstanding derivatives by $10.7 million to a fair market value of $16.3 million; and conversely a hypothetical ten percent decrease in the cost of product would decrease the fair market value of these outstanding derivatives by $6.5 million to a fair market value of $(0.9) 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, 2010. 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, 2010 at the reasonable level of assurance. For purposes of Rule 13a-15(e), the term disclosure controls and procedures means controls and other procedures of an issuer that are designed to ensure that information required to be disclosed by the issuer in the reports that it files or submits under the Act (15 U.S.C. 78a et seq.) is recorded, processed, summarized and reported, within the time periods specified in the Commission’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Act is accumulated and communicated to the issuer’s management, including its principal executive and principal financial officer, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

(b) 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, 2010. The effectiveness of our internal control over financial reporting as of September 30, 2010 has been audited by our independent registered public accounting firm, as stated in their report which is included herein.

On May 10, 2010, the Partnership completed the acquisition of Champion Energy Corporation (“CEC”). The Partnership is in the process of integrating CEC and as such it has been excluded by management from it’s assessment of the effectiveness of the Partnership’s internal control over financial reporting as of September 30, 2010, CEC’s internal control over financial reporting that is associated with total assets of $74 million (of which $52 million represents goodwill and intangibles included within the scope of the assessment) and total revenues of $25 million in the consolidated financial statements of the Partnership as of and for the year ended September 30, 2010.

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

(d) Other.

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 detected. Therefore, a control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Our disclosure controls and procedures are designed to provide such reasonable assurances of achieving our desired control objectives, and the principal executive officer and principal financial officer of our general partner have concluded, as of September 30, 2010, that our disclosure controls and procedures were effective in achieving that level of reasonable assurance.

ITEM 9B.

OTHER INFORMATION

Not applicable.

PART III

ITEM 10.

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Partnership Management

The general partner of the Partnership is Kestrel Heat, LLC. The Board of Directors of Kestrel Heat, LLC is appointed by its sole member, Kestrel Energy Partners, LLC. Kestrel Energy Partners, LLC is a private equity investment partnership formed by Yorktown Energy Partners VI, L.P., Paul A. Vermylen and other investors.

The Partnership’s operations are conducted through Petro Holdings, Inc. and its subsidiaries. Petro Holdings, Inc. is a corporation that is a wholly-owned subsidiary of Star Acquisitions, which is a wholly-owned subsidiary of the Partnership.

Kestrel Heat, LLC as the general partner of the Partnership, oversees the activities of the Partnership. Unitholders do not directly or indirectly participate in the management or operation of the Partnership or elect the directors of the general partner. The Board of Directors of the general partner 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, 2010, Kestrel Heat, LLC and its affiliates owned an aggregate of 12,803,128 common units, representing 19.09% 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 appointed for an indefinite term, subject to the discretion of Kestrel Energy Partners, LLC. The following table shows certain information for directors and executive officers of the general partner as of November 30, 2010:


Name	Age		Position
Paul A. Vermylen, Jr.		63	Chairman, Director
Daniel P. Donovan		64	President, Chief Executive Officer and Director
Richard F. Ambury		53	Executive Vice President and Chief Financial Officer
Steven J. Goldman		50	Executive Vice President and Chief Operating Officer
Richard G. Oakley		50	Vice President and Controller
Henry D. Babcock ⁽¹⁾		70	Director
C. Scott Baxter ⁽¹⁾		49	Director
Bryan H. Lawrence		68	Director
Sheldon B. Lubar		81	Director
William P. Nicoletti ⁽¹⁾		65	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 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. and Moneta Energy Services Ltd. Mr. Vermylen is a graduate of Georgetown University and has a M.B.A. from Columbia University.

Mr. Vermylen’s substantial experience in the home heating oil industry and his leadership skills and experience as an executive officer of Meenan, among other factors, led the Board to conclude that he should serve as a director of Kestrel Heat.

Daniel P. Donovan. Mr. Donovan has been Chief Executive Officer of Kestrel Heat since 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 Chief Operating Officer of Kestrel Heat. Mr. Donovan was President and Chief Operating Officer of Star Gas from March 2005 until April 28, 2006. From May 2004 to March 2005 he was President and Chief Operating Officer of the Star Gas heating oil segment. Mr. Donovan held various management positions with Meenan Oil Co. LP, from January 1980 to May 2004, 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.

Mr. Donovan’s in-depth knowledge of the Partnership’s business as its chief executive officer and his substantial experience in the home heating oil industry, among other factors, led the Board to conclude that he should serve as a director of Kestrel Heat.

Richard F. Ambury. Mr. Ambury has been Executive Vice President of Kestrel Heat since May 1, 2010 and 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 Executive Vice President and Chief Operating Officer of Kestrel Heat since May 1, 2010 and was Senior Vice President of Operations of the Partnership from May 31, 2007 until April 30, 2010. 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 Global Education Advisory Board of Save the Children and is President of the Caumsett Foundation.

Mr. Babcock’s significant experience in capital markets, corporate finance and venture capital, among other factors, led the Board to conclude that he should serve as a director of Kestrel Heat.

C. Scott Baxter. Mr. Baxter has been a director of Kestrel Heat since April 28, 2006. Mr. Baxter is currently the Managing Partner for Green River Energy Partners, an energy investment banking firm headquartered in New York. Previously, Mr. Baxter was Managing Director & Head of the Global Energy Group for Houlihan Lokey who had acquired his previous firm’s assets, Green River Energy. At Green River Energy, Mr. Baxter was the Managing Partner and conducted M&A advisory and invested in public and private equity. 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. Since 1996, Mr. Baxter has also been on the President’s advisory board for Weber State University.

Mr. Baxter’s significant experience as an investor and senior investment banker focused on the energy field, among other factors, led the Board to conclude that he should serve as a director of Kestrel Heat.

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 was employed 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.

Mr. Lawrence’s significant financial and investment experience, and experience as a founder of Yorktown Energy Partners LLC, among other factors, led the Board to conclude that he should serve as a director of Kestrel Heat.

Sheldon 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 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.

Mr. Lubar’s significant experience as a senior executive officer and as a director of other public company’s, among other factors, led the Board to conclude that he should serve as a director of Kestrel Heat.

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. Since February 1, 2009, he has been a Managing Director of Parkman Whaling LLC, a Houston, Texas based energy investment banking firm. Previously, he was 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. Mr. Nicoletti is a graduate of Seton Hall University and received an M.B.A. from Columbia University.

Mr. Nicoletti’s current and prior leadership experience in the energy investment banking industry and his significant experience in finance, accounting and corporate governance matters, among other factors, led the Board to conclude that he should serve as a director of Kestrel Heat.

Director Independence

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 2010, the Board of Directors of Kestrel Heat, LLC met nine times. All directors attended each meeting except for two meetings which 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, which 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) 328-7310. 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.

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 2010, the Audit Committee of Kestrel Heat, LLC met seven 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 Investor Relations, (203) 328-7310.

Section 16(a) Beneficial Ownership Reporting Compliance

Based on copies of reports furnished to us, we believe that during fiscal year 2009, all reporting persons complied with the Section 16(a) filing requirements applicable to them.

Non-Management Directors and Interested Party Communications

The non-management directors on the Board of 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.

ITEM 11.

EXECUTIVE COMPENSATION

Compensation Discussion And Analysis

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.

As a limited partnership 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 the majority of the Board are not employees, the Board determined that it has adequate independence to act in the capacity 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 (“CEO”) during fiscal 2010, each person who served as chief financial officer (“CFO”) during fiscal 2010 and the two other most highly compensated executive officers serving at September 30, 2010 (there being no other executive officers who earned more than $100,000 during fiscal 2010) are referred to as the “named executive officers” and are included in the Summary Compensation Table below.

In this Compensation Discussion and Analysis, we address the compensation paid or awarded to Messrs. Donovan, Ambury, Goldman, and Oakley. We refer to these executive officers as our “named executive officers.”

Compensation decisions for the above officers were made by the Board of Directors of the Partnership.

COMPENSATION PHILOSOPHY AND POLICIES

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 and to reward individual contributions to our success. The Board of Directors considers the following policies in determining the compensation of the named executive officers:

•

compensation should be related to the performance of the individual executive and the performance measured against both financial and non-financial achievements;

•

compensation levels should be competitive to ensure that we will be able to attract, motivate and retain highly qualified executive officers; and

•

compensation should be related to improving unitholder value.

Compensation Methodology

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 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., 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.

Elements of Executive Compensation

For the fiscal year ended September 30, 2010, 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, CFO and COO, 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- Controller, approximately 65% of the annual compensation is in the form of base salary and 35% is from the discretionary profit sharing allocations. During fiscal 2010, $40,000 was paid to the named officers under the terms of the Partnership’s long-term incentive plan and represented a small portion of its executive compensation. The majority of the Partnership’s compensation allocation was weighted towards base salary and annual discretionary profit sharing allocation.

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 2010 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 2010 unless the Partnership achieved actual adjusted EBITDA for fiscal 2010 of at least 70% of the amount of budgeted adjusted EBITDA for fiscal 2010. 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 2010 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. 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;

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.

The Partnership distributed approximately $116,000 in Incentive Distributions during fiscal 2010, initiating payments to the named executive officers of approximately $40,000 under its long-term incentive plan. 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 0% to 60% 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 2010 Compensation Decisions

For fiscal 2010, 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, 2010 and the percentage increase in his base salary over October 1, 2009. 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. In addition, the increases to Messrs. Ambury and Goldman reflect Mr. Ambury’s promotion to Executive Vice President and Mr. Goldman’s promotion to Executive Vice President and Chief Operating Officer. The average percentage increase in base salary for executives in our peer group was 5.2%.


Name	Salary		Percentage Over Prior Year
Daniel P. Donovan	$	405,000		3.6	%
Richard F. Ambury	$	325,000		6.2	%
Steven J. Goldman	$	315,000		9.8	%
Richard G. Oakley	$	212,800		3.5	%

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 4.5% lower than the bonus amounts for fiscal 2009. One of the Partnership’s primary performance measures is Adjusted EBITDA. Adjusted EBITDA for profit sharing purposes decreased by $6.8 million, or 8.3%, to $76.0 million for fiscal 2010. The average percentage decrease in Adjusted EBITDA for companies in our peer group was 10.6%.

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 2010, an additional 10 participation points were awarded to Mr. Oakley under the Plan.

In fiscal 2010, $40,000 was paid to the named executive officers under the Long-Term Management Incentive Compensation Plan.

Retirement and Health Benefits

There were no changes to the retirement and health benefits applicable to the named executive officers in fiscal 2010.

Employment Contracts and Severance Agreements

Agreement with Daniel P. Donovan

The Partnership entered into an employment agreement on November 8, 2010 with Mr. Donovan effective as of June 1, 2010. Mr. Donovan’s employment agreement is for a term of three-years unless otherwise terminated in accordance with the employment agreement. Mr. Donovan will serve as President and Chief Executive Officer of the Partnership and its subsidiaries. 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

The Partnership entered into an employment agreement with Mr. Ambury effective as of April 28, 2008. Mr. Ambury will serve as Chief Financial Officer and Treasurer of the Partnership and its subsidiaries. The employment agreement provides for one year’s salary as severance if Mr. Ambury’s employment is terminated without cause or by Mr. Ambury for good reason.

Agreement with Steven J. Goldman

Effective May 31, 2007 Steven J. 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 November 2, 2009, the Partnership entered into an agreement with Mr. Richard G. Oakley pursuant to which Mr. Oakley will continue to be employed as Vice President—Controller on an at-will basis, and provides for one year’s salary as severance if his employment is terminated for reasons other than cause.

Change In Control Agreements

On December 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, Chief Financial Officer. Under the terms of each agreement, if the above mentioned executive officer’s employment is terminated as a result of a change in control (as defined in the agreement) that executive officer will be entitled to a payment equal to two times their base annual salary in the year of such termination plus two times the average amount paid as a bonus and/or as profit sharing during the three years preceding the year of such termination. The term change in control means the present equity owners of Kestrel and their affiliates collectively cease to beneficially own equity interests having the voting power to elect at least a majority of the members of the board of directors or other governing board of the general partner of the Partnership or any successor entity to the Partnership. If a change in control were to have occurred as of the date of this report, Mr. Donovan would have received a payment of $1.8 million and Mr. Ambury would have received a payment of $1.4 million.

Indemnification 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.

Board of Directors Report

The Board of Directors of the general partner of the Partnership does not have a separate compensation committee. Executive compensation is determined by the Board of Directors. Mr. Donovan is President, Chief Executive Officer and a Director.

The Board of Directors reviewed and discussed with the Partnership’s management the Compensation Discussion and Analysis contained in this annual report on Form 10-K. Based on that review and discussion, the Board of Directors recommends that the Compensation Discussion and Analysis be included in the Partnership’s annual report on Form 10-K for the year ended September 30, 2010.

Paul A. Vermylen, Jr.

Daniel P. Donovan

Henry D. Babcock

C. Scott Baxter

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		2010	$	395,667		—		—		—	$	565,000	$	85,384		$	55,760	$	1,101,811
President and Chief Executive Officer		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

Richard F. Ambury		2010	$	313,917		—		—		—	$	445,000	$	30,699		$	47,852	$	837,468
Chief Financial Officer, Treasurer and Executive Vice President		2009	$	302,500		—		—		—	$	485,000	$	64,798		$	30,722	$	883,020
		2008	$	292,028		—		—		—	$	260,000	$	(19,423	)	$	27,855	$	560,460

Steven J. Goldman		2010	$	298,667		—		—		—	$	361,000	$	—		$	44,719	$	704,386
Chief Operating Officer and Executive Vice President		2009	$	285,000		—		—		—	$	337,000	$	—		$	33,404	$	655,404
Chief Operating Officer and Executive Vice President		2008	$	277,000		—		—		—	$	182,000	$	—		$	30,085	$	489,085

Richard G. Oakley		2010	$	205,600		—		—		—	$	145,000	$	42,887		$	32,491	$	425,978
Vice President - Controller		2009	$	199,600		—		—		—	$	150,000	$	88,066		$	29,284	$	466,950
		2008	$	195,700		—		—		—	$	84,000	$	(27,678	)	$	26,657	$	278,679

(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	Long Term Management Compensation Plan(s)		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		16,989		18,374		20,397		55,760
Richard F. Ambury		13,308		15,344		19,200		47,852
Steven J. Goldman		8,494		16,204		20,021		44,719
Richard G. Oakley		1,699		13,992		16,800		32,491

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	$	790,834	$	—
Richard F. Ambury	Retirement Plan		13	$	152,457	$	—
	Supplemental Employee Retirement Plan		—	$	29,177	$	—
Steven J. Goldman	Retirement Plan		—	$	—	$	—
Richard G. Oakley	Retirement Plan		19	$	232,760	$	—

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	$	405,000	$	1,816,667
Richard F. Ambury	$	325,000	$	1,443,333
Steven J. Goldman	$	315,000	$	—
Richard G. Oakley	$	212,800	$	—

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)	$	132,000		—		—		—	$	83,863		—	$	215,863
Daniel P. Donovan (2)	$	—		—		—		—		—		—	$	—
Henry D. Babcock (3)	$	55,500		—		—		—		—		—	$	55,500
C. Scott Baxter (3)	$	55,500		—		—		—		—		—	$	55,500
Bryan H. Lawrence (4)	$	—		—		—		—		—		—	$	—
Sheldon B. Lubar	$	39,750		—		—		—		—		—	$	39,750
William P. Nicoletti (5)	$	62,250		—		—		—		—		—	$	62,250

(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 $30,000 plus $1,500 for each regular and telephonic meeting attended. The Chairman of the Audit Committee receives an annual fee of $12,000 while other Audit Committee members receive an annual fee of $6,000. Each member of the Audit Committee receives $1,500 for every regular and 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 November 30, 2010 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		19.09	%		325,729		100.00	%
Paul A. Vermylen, Jr.		155,000		*
Daniel P. Donovan		19,500		*
Steven J. Goldman		5,000		*
Richard F. Ambury		12,125		*
Richard G. Oakley		—		—
Henry D. Babcock		96,121		*
C. Scott Baxter		75,000		*
Bryan H. Lawrence		—		—
Sheldon B. Lubar		—		—
William P. Nicoletti		35,000		*

All officers and directors and Kestrel Heat, LLC as a group (10 persons)		13,200,874		19.68	%		325,729		100.00	%
Bandera Partners LLC (b)		8,573,509		12.78	%

(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.

(b)	According to a Form 4 filed with the SEC on September 17, 2010, Bandera Partners LLC is the investment manager of Bandera Master Fund and may be deemed to have beneficial ownership of the common units.

*	Amount represents less than 1%.

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”).

Policies Regarding Transactions with Related Persons

Our Code of Business Conduct and Ethics, 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.

For the years ended September 30, 2010, 2009 and 2008, the Partnership had no related party transactions or agreements pursuant to Item 404 of regulation S-K.

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.

Our 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. Although the Partnership Governance Guidelines by their terms only apply to directors the Board intends to apply this requirement to officers and employees and their affiliates.

To 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

(D)

such additional factors as the General Partner (including the Conflicts Committee) determines in its sole discretion to be relevant, reasonable or appropriate under the circumstances.

ITEM 14.

PRINCIPAL ACCOUNTANT FEES AND SERVICES

The following table represents the aggregate fees for professional audit services rendered by KPMG LLP including fees for the audit of the Partnership’s annual financial statements for the fiscal years 2010 and 2009, and for fees billed and accrued for other services rendered by KPMG LLP (in thousands).


	2010		2009
Audit Fees ⁽¹⁾	$	1,555	$	1,510
Tax Fees ⁽²⁾		426		481

Total Fees	$	1,981	$	1,991

⁽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


Exhibit Number	Incorp by Ref. 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	*	Amendment No. 2 to Second Amended and Restated Agreement of Limited Partnership

4.4	99.1(3)	Amended and Restated Unit Purchase Rights Agreement dated as of July 20, 2006

4.5	4.4(8)	First Amendment to Amended and Restated Unit Purchase Rights Agreement dated as of June 7, 2007

4.6	(12)	Second Amendment to Amended and Restated Unit Purchase Rights Agreement dated May 21, 2009.

10.1	99.2(5)	Letter Agreement and general release dated March 7, 2005 between Star Gas Partners L.P. and Irik P. Sevin†

10.2	99.1(6)	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

10.3	99.2(2)	Indenture dated as of April 28, 2006 for the new senior notes due 2013

10.4	99.3(2)	Amended and Restated Indenture dated as of April 28, 2006 for the existing senior notes due 2013

10.5	99.2(3)	Management Incentive Compensation Plan†

10.6	99.4(3)	Form of Indemnification Agreement for Officers and Directors.

10.7	(4)	Approved Dealer / Contractor Agreement dated as of July 11, 2006 by and between AFC First Financial Corporation and Petro Holdings, Inc.

10.8	99.4(7)	Form of Amendment No. 1 to Indemnification Agreement.

10.9	(9)	Description of 2008 Profit Sharing Plan.†

10.10	(10)	Employment Agreement dated December 3, 2007 between Star Gas Partners, L.P. and Steven J. Goldman.†

10.11	(10)	Change in Control Agreement dated December 4, 2007 between Star Gas Partners, L.P. and Daniel P. Donovan.†

10.13	(10)	Change in Control Agreement dated December 4, 2007 between Star Gas Partners, L.P. and Richard F. Ambury.†

10.14	(11)	Employment Agreement dated April 28, 2008 between Star Gas Partners, L.P. and Richard Ambury†

10.15	(13)	Amended and Restated Credit Agreement dated as of July 2, 2009.

10.16	(14)	Agreement dated November 2, 2009 between Star Gas Partners, L.P. and Richard G. Oakley.†

10.17	(15)	First Amendment dated as of January 21, 2010, to Amended and Restated Credit Agreement dated as of July 2, 2009.


Exhibit Number	Incorp by Ref. to Exh.	Description
10.18	*	Third Amendment dated as of November 16, 2010 to Amended and Restated Credit Agreement dated as of July 9, 2009.

10.19	(16)	Equity Purchase Agreement dated as of May 10, 2010.

10.20	(17)	Employment Agreement dated as of November 8, 2010 between Star Gas Partners, L.P. and Daniel P. Donovan.

10.21	*	Purchase Agreement, dated as of November 10, 2010 between Star Gas Partners, L.P., J.P. Morgan Securities LLC and RBS.

10.22	*	Registration Rights Agreement, dated as of November 16, 2010 between Star Gas Partners, L.P. and J.P. Morgan Securities LLC.

10.23	*	Indenture dated as of November 16, 2010 for the 8.875% Senior Notes due 2017.

14	(11)	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

†	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 an exhibit to the Registrant’s Annual Report on Form 10-K for the fiscal year ended September 30, 2006, filed with the Commission on January 17, 2007.

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

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

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

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

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

(10)	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.

(11)	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.

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

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

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

(15)	Incorporated by reference to an exhibit to the Registrant’s Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2010.

(16)	Incorporated by reference to an exhibit to the Registrant’s Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2010.

(17)	Incorporated by reference to an exhibit to the Registrant’s Current Report on Form 8-K dated November 12, 2010.

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/ Daniel P. Donovan
		Daniel P. 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

/s/ Daniel P. Donovan Daniel P. Donovan	President and Chief Executive Officer and Director Kestrel Heat, LLC	December 9, 2010

/s/ Richard F. Ambury Richard F. Ambury	Chief Financial Officer (Principal Financial Officer) Kestrel Heat, LLC	December 9, 2010

/s/ Richard G. Oakley Richard G. Oakley	Vice President—Controller (Principal Accounting Officer) Kestrel Heat, LLC	December 9, 2010

/s/ Paul A. Vermylen, Jr. Paul A. Vermylen, Jr.	Non-Executive Chairman of the Board and Director Kestrel Heat, LLC	December 9, 2010

/s/ Henry D. Babcock Henry D. Babcock	Director Kestrel Heat, LLC	December 9, 2010

/s/ C. Scott Baxter C. Scott Baxter	Director Kestrel Heat, LLC	December 9, 2010

/s/ Bryan H. Lawrence Bryan H. Lawrence	Director Kestrel Heat, LLC	December 9, 2010

/s/ Sheldon B. Lubar Sheldon B. Lubar	Director Kestrel Heat, LLC	December 9, 2010

/s/ William P. Nicoletti William P. Nicoletti	Director Kestrel Heat, LLC	December 9, 2010

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/ Daniel P. Donovan
		Daniel P. 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

/s/ Daniel P. Donovan Daniel P. Donovan	President, Chief Executive Officer and Director (Principal Executive Officer) Star Gas Finance Company	December 9, 2010

/s/ RICHARD F. AMBURY Richard F. Ambury	Chief Financial Officer (Principal Financial Officer) Star Gas Finance Company	December 9, 2010

/s/ RICHARD G. OAKLEY Richard G. Oakley	Vice President—Controller (Principal Accounting Officer) Star Gas Finance Company	December 9, 2010

STAR GAS PARTNERS, L.P. AND SUBSIDIARIES

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

AND FINANCIAL STATEMENT SCHEDULE


		Page
Part II Financial Information:

	Item 8—Financial Statements

	Report of Independent Registered Public Accounting Firm		F-2

	Consolidated Balance Sheets as of September 30, 2010 and September 30, 2009		F-3

	Consolidated Statements of Operations for the years ended September 30, 2010, September 30, 2009 and September 30, 2008		F-4

	Consolidated Statements of Partners’ Capital and Comprehensive Income (Loss) for the years ended September 30, 2010, September 30, 2009 and September 30, 2008		F-5

	Consolidated Statements of Cash Flows for the years ended September 30, 2010, September 30, 2009 and September 30, 2008		F-6

	Notes to Consolidated Financial Statements		F-7 – F-28

	Schedules for the years ended September 30, 2010, September 30, 2009 and September 30, 2008

	I. Condensed Financial Information of Registrant		F-29 – F-31

	II. Valuation and Qualifying Accounts		F-32

	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

Report of Independent Registered Public Accounting Firm

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

We have audited the accompanying consolidated balance sheets of Star Gas Partners, L.P. and Subsidiaries (the “Partnership”) as of September 30, 2010 and 2009, and the related consolidated statements of operations, partners’ capital and comprehensive income (loss), and cash flows for each of the years in the three-year period ended September 30, 2010. In connection with our audits of the consolidated financial statements, we have also audited the financial statement schedules I and II listed in the accompanying index. We also have audited the Partnership’s internal control over financial reporting as of September 30, 2010, 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 financial statement schedules, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedules and an opinion on the Partnership’s internal control over financial reporting based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the consolidated financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Star Gas Partners, L.P. and Subsidiaries as of September 30, 2010 and 2009, and the results of its operations and its cash flows for each of the years in the three-year period ended September 30, 2010, in conformity with U.S. generally accepted accounting principles. In addition, in our opinion, the related financial statement schedules I and II listed in the accompanying index, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein. Also in our opinion, Star Gas Partners, L.P. and Subsidiaries maintained, in all material respects, effective internal control over financial reporting as of September 30, 2010, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

Star Gas Partners, L.P. acquired Champion Energy Corporation (“CEC”) during 2010, and management excluded from its assessment of the effectiveness of the Partnership’s internal control over financial reporting as of September 30, 2010, CEC’s internal control over financial reporting associated with total assets of $74 million (of which $52 million represents goodwill and intangibles included within the scope of the assessment) and total revenues of $25 million included in the consolidated financial statements of the Partnership as of and for the year ended September 30, 2010. Our audit of internal control over financial reporting of Star Gas Partners, L.P. also excluded an evaluation of the internal control over financial reporting of Champion Energy Corporation.

KPMG LLP

Stamford, Connecticut

December 9, 2010

F-2

STAR GAS PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS


	Years Ended September 30,
(in thousands)	2010			2009
ASSETS
Current assets
Cash and cash equivalents	$	61,062		$	195,160
Receivables, net of allowance of $5,443 and $6,267, respectively		70,443			58,854
Inventories		66,734			62,636
Fair asset value of derivative instruments		7,158			14,676
Current deferred tax asset, net		20,247			30,135
Prepaid expenses and other current assets		21,219			15,437

Total current assets		246,863			376,898

Property and equipment, net		44,712			37,494
Long-term portion of accounts receivables		583			504
Goodwill		199,052			182,942
Intangibles, net		58,894			20,468
Long-term deferred tax asset, net		26,551			36,265
Deferred charges and other assets, net		5,853			9,555

Total assets	$	582,508		$	664,126

LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities
Accounts payable	$	16,626		$	17,103
Fair liability value of derivative instruments		1,586			665
Accrued expenses and other current liabilities		68,854			64,446
Unearned service contract revenue		40,110			37,121
Customer credit balances		68,762			74,153

Total current liabilities		195,938			193,488

Long-term debt		82,770			133,112
Other long-term liabilities		23,889			31,192
Partners’ capital
Common unitholders		307,092			332,340
General partner		290			309
Accumulated other comprehensive income (loss), net of taxes		(27,471	)		(26,315	)

Total partners’ capital		279,911			306,334

Total liabilities and partners’ capital	$	582,508		$	664,126

See accompanying notes to consolidated financial statements.

F-3

STAR GAS PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS


	Years Ended September 30,
(in thousands, except per unit data)	2010			2009			2008
Sales:
Product	$	1,028,423		$	1,032,812		$	1,353,950
Installations and service		184,353			174,001			189,143

Total sales		1,212,776			1,206,813			1,543,093
Cost and expenses:
Cost of product		734,594			708,185			1,081,833
Cost of installations and service		169,453			167,570			175,759
(Increase) decrease in the fair value of derivative instruments		(5,622	)		(13,690	)		25,467
Delivery and branch expenses		218,625			224,478			213,902
Depreciation and amortization expenses		15,745			19,406			26,784
General and administrative expenses		21,397			20,742			16,043

Operating income		58,584			80,122			3,305

Interest expense		(14,326	)		(17,842	)		(20,691	)
Interest income		3,506			4,205			6,883
Amortization of debt issuance costs		(2,680	)		(2,750	)		(2,339	)
Gain (loss) on redemption of debt		(1,132	)		9,706			—

Income (loss) before income taxes		43,952			73,441			(12,842	)
Income tax expense (benefit)		15,632			(57,597	)		566

Net income (loss)	$	28,320		$	131,038		$	(13,408	)

General Partner’s interest in net income (loss)		128			561			(57	)

Limited Partners’ interest in net income (loss)	$	28,192		$	130,477		$	(13,351	)

Basic and diluted income (loss) per Limited Partner Unit (1):	$	0.38		$	1.43		$	(0.18	)

Weighted average number of Limited Partner units outstanding:
Basic		70,019			75,738			75,774

Diluted		70,019			75,738			75,774

(1)	See Note 17 Earnings Per Limited Partner Units.

See accompanying notes to consolidated financial statements.

F-4

STAR GAS PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL AND COMPREHENSIVE INCOME (LOSS)

Years Ended September 30, 2010, 2009 and 2008


	Number of Units
(in thousands)	Common			General Partner		Common			General Partner			Accum. Other Comprehensive Income (Loss)			Total Partners’ Capital
Balance as of September 30, 2007		75,774			326		232,895			(129	)		(16,435	)		216,331
Net loss							(13,351	)		(57	)					(13,408	)
Unrealized loss on pension plan obligation													(2,946	)		(2,946	)

Total comprehensive loss		—			—		(13,351	)		(57	)		(2,946	)		(16,354	)

Balance as of September 30, 2008		75,774			326		219,544			(186	)		(19,381	)		199,977
Net income							130,477			561						131,038
Unrealized loss on pension plan obligation													(11,854	)		(11,854	)
Tax affect of unrealized loss on pension plan obligation													4,920			4,920

Total comprehensive income		—			—		130,477			561			(6,934	)		124,104
Distributions							(15,345	)		(66	)					(15,411	)
Retirement of units (1)		(637	)				(2,336	)								(2,336	)

Balance as of September 30, 2009		75,137			326	$	332,340		$	309		$	(26,315	)	$	306,334
Net income							28,192			128						28,320
Unrealized loss on pension plan obligation													(1,977	)		(1,977	)
Tax affect of unrealized loss on pension plan obligation													821			821

Total comprehensive income		—			—		28,192			128			(1,156	)		27,164
Distributions							(20,206	)		(147	)					(20,353	)
Retirement of units (1)		(8,059	)				(33,234	)								(33,234	)

Balance as of September 30, 2010		67,078			326	$	307,092		$	290		$	(27,471	)	$	279,911

(1)	See Note 2—Common Unit Repurchase and Retirement.

See accompanying notes to consolidated financial statements.

F-5

STAR GAS PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Years Ended September 30,
(in thousands)	2010			2009			2008
Cash flows provided by (used in) operating activities:
Net income (loss)	$	28,320		$	131,038		$	(13,408	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
(Increase) decrease in fair value of derivative instruments		(5,622	)		(13,690	)		25,467
Depreciation and amortization		18,425			22,157			29,123
(Gain) loss on redemption of debt		1,132			(9,706	)		—
Provision for losses on accounts receivable		5,279			10,310			11,961
Change in deferred taxes		13,331			(61,355	)		—
Changes in operating assets and liabilities net of amounts related to acquisitions:
(Increase) decrease in receivables		(4,570	)		26,657			(28,002	)
(Increase) decrease in inventories		(2,012	)		(17,747	)		41,368
(Increase) decrease in other assets		13,912			4,230			(8,797	)
Increase (decrease) in accounts payable		(1,784	)		216			(1,937	)
Increase (decrease) in customer credit balances		(9,250	)		(11,964	)		13,390
Increase (decrease) in other current and long-term liabilities		(12,732	)		(1,691	)		2,390

Net cash provided by operating activities		44,429			78,455			71,555

Cash flows provided by (used in) investing activities:
Capital expenditures		(5,567	)		(4,334	)		(4,145	)
Proceeds from sales of fixed assets		392			159			533
Acquisitions (net of cash acquired of $3,377, $0, and $0, respectively)		(68,658	)		(3,393	)		(1,876	)
Earnout		(123	)		—			—

Net cash used in investing activities		(73,956	)		(7,568	)		(5,488	)

Cash flows provided by (used in) financing activities:
Revolving credit facility borrowings		36,754			—			57,161
Revolving credit facility repayments		(36,754	)		—			(57,161	)
Repayment of debt		(50,854	)		(30,230	)
Distributions		(20,353	)		(15,411	)		—
Unit repurchase		(33,234	)		(2,336	)		—
Increase in deferred charges		(130	)		(6,558	)		(145	)

Net cash used in financing activities		(104,571	)		(54,535	)		(145	)

Net increase (decrease) in cash		(134,098	)		16,352			65,922
Cash and equivalent at beginning of period		195,160			178,808			112,886

Cash and equivalent at end of period	$	61,062		$	195,160		$	178,808

See accompanying notes to consolidated financial statements.

F-6

STAR GAS PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1) Partnership Organization

Star Gas Partners, L.P. (“Star Gas Partners,” the “Partnership,” “we,” “us,” or “our”) is a home heating oil distributor and services provider with one reportable operating segment that principally provides services to residential and commercial customers to heat their homes and buildings. Star Gas Partners is a master limited partnership, which at September 30, 2010, had outstanding 67.1 million common units (NYSE: “SGU”) representing 99.5% limited partner interest in Star Gas Partners, and 0.3 million general partner units, representing 0.5% general partner interest in Star Gas Partners.

The Partnership is organized as follows:

•

The general partner of the Partnership is Kestrel Heat, LLC, a Delaware limited liability company (“Kestrel Heat” or the “general partner”). The Board of Directors of Kestrel Heat is appointed by its sole member, Kestrel Energy Partners, LLC, a Delaware limited liability company (“Kestrel”).

•

The Partnership’s operations are conducted through Petro Holdings, Inc. and its subsidiaries (“Petro”). Petro is a Minnesota corporation that is an indirect wholly-owned subsidiary of the Partnership. Petro is a Northeast and Mid-Atlantic region retail distributor of home heating oil that at September 30, 2010 served approximately 404,000 full-service residential and commercial home heating oil customers, and 10,000 propane customers. Petro also sold home heating oil, gasoline and diesel fuel to approximately 35,000 customers on a delivery only basis. In addition, Petro installed, maintained, and repaired heating and air conditioning equipment for its customers, and provided ancillary home services, including home security and plumbing, to approximately 11,000 customers.

•

Star Gas Finance Company is a 100% owned subsidiary of the Partnership. Star Gas Finance Company serves as the co-issuer, jointly and severally with the Partnership, of its September 30, 2010 $82.5 million 10.25% Senior Notes (excluding discounts and premiums) due 2013, that on November 16, 2010 was called for redemption subsequent to the Partnership’s issuance of its $125.0 million 8.875% Senior Notes due 2017 (excluding discounts and premiums). The Partnership is dependent on distributions including inter-company interest payments from its subsidiaries to service the Partnership’s debt obligations. The distributions from the Partnership’s subsidiaries are not guaranteed and are subject to certain loan restrictions. Star Gas Finance Company has nominal assets and conducts no business operations. (See Note 10—Long-Term Debt and Bank Facility Borrowings)

2) Common Unit Repurchase and Retirement

On July 19, 2010, the Board of Directors of the Partnership’s General Partner authorized the repurchase of up to 7.0 million of the Partnership’s common units (“Plan II”). The authorized common unit repurchases may be made from time-to-time in the open market, in privately negotiated transactions or in such other manner deemed appropriate by management. In order to facilitate the repurchase program, the Partnership entered into a prearranged unit repurchase plan under Rule 10b5-1 of the Securities Act of 1933, as amended for up to 4.0 million common units with a third party broker. There is no guarantee of the exact number of units that will be purchased under the program and the Partnership may discontinue purchases at any time. The program does not have a time limit. The Partnership’s repurchase activities take into account SEC safe harbor rules and guidance for issuer repurchases. All of the common units purchased in the repurchase program will be retired.

F-7

(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 (a)		Maximum Number of Units that May Yet Be Purchased Under the Plan I Program
Plan I - Number of units authorized						7,500

Plan I - Fiscal year 2009 total		637	$	3.67		6,863

October 2009		3,072	$	3.97		3,791
November 2009		350	$	3.96		3,441
December 2009		834	$	3.95		2,607

Plan I - First quarter fiscal year 2010 total		4,256	$	3.97		2,607

January 2010		—	$	—		2,607
February 2010		964	$	4.03		1,643
March 2010		—	$	—		1,643

Plan I - Second quarter fiscal year 2010 total		964	$	4.03		1,643

April 2010		110	$	4.30		1,533
May 2010		254	$	4.36		1,279
June 2010		1,279	$	4.36		—

Plan I - Third quarter fiscal year 2010 total		1,643	$	4.36		—

Plan I - Total number of units repurchased		7,500	$	4.04

Plan II - Number of units authorized						7,000
July 2010		—	$	—		7,000
August 2010		1,063	$	4.43		5,937
September 2010		134	$	4.51		5,803

Plan II - Fourth quarter fiscal year 2010 total		1,197	$	4.44		5,803

(a)	Amounts include repurchase costs.

3) Summary of Significant Accounting Policies

Basis of Presentation

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

Reclassification

Certain prior year amounts have been reclassified to conform with the current year presentation.

Use of Estimates

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

F-8

Revenue Recognition

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

Cost of Product

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

Cost of Installations and Service

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

Delivery and Branch Expenses

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

General and Administrative Expenses

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

Allowance for Doubtful Accounts

The Partnership periodically reviews past due customer accounts receivable balances. After giving consideration to economic conditions, overdue status and other factors, it establishes an allowance for doubtful accounts, representing the Partnership’s best estimate of amounts that may not be collectible.

Allocation of Net Income (Loss)

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

Net Income (Loss) per Limited Partner Unit

Income per limited partner unit is computed in accordance with FASB ASC 260-10-05 Earnings Per Share topic, Master Limited Partnerships subtopic (EITF 03-6), by dividing the limited partners’ interest in net income by the weighted average number of limited partner units outstanding. The pro forma nature of the allocation required by this standard provides that in any accounting period where the Partnership’s aggregate net income exceeds its aggregate distribution for such period, the Partnership is required to present net income per limited partner unit as if all of the earnings for the periods were distributed, regardless of whether those earnings would actually be distributed during a particular period from an economic or practical perspective. This allocation does not impact the Partnership’s overall net income or other financial results. However, for periods in which the Partnership’s aggregate net income exceeds its aggregate distributions for such period, it will have the impact of reducing the earnings per limited partner unit, as the calculation according to this standard results in a theoretical increased allocation of undistributed earnings to the general partner. In accounting periods where aggregate net income does not exceed aggregate distributions for such period, this standard does not have any impact on the Partnership’s net income per limited partner unit calculation. A separate and independent calculation for each quarter and year-to-date period is required.

F-9

Until the quarter ended March 31, 2009, either the partners had no rights to accrue or receive distributions, or the earnings of the period did not exceed the aggregate distributions.

Cash, Accounts Receivable, Notes Receivable, Revolving Credit Facility Borrowings, and Accounts Payable

The carrying amount of cash, accounts receivable, notes receivable, revolving credit facility borrowings, and accounts payable approximates fair value because of the short maturity of these instruments.

Cash Equivalents

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

Inventories

Heating oil and other fuels inventory are stated at the lower of cost or market using the weighted average cost method of accounting. All other inventories, representing parts and equipment are stated at the lower of cost or market using the FIFO method.

Property, and Equipment

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

Goodwill and Intangible Assets

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

Goodwill is the excess of cost over the fair value of net assets in the acquisition of a company. In accordance with FASB ASC 350-10-05 Intangibles-Goodwill and Other topic, goodwill and intangible assets with indefinite useful lives are not amortized, but instead are annually tested for impairment. Also in accordance with this standard, intangible assets with definite useful lives are amortized over their respective estimated useful lives to their estimated residual values, and reviewed for impairment. The Partnership performs its annual impairment review during its fiscal fourth quarter or more frequently if events or circumstances indicate that the value of goodwill might be impaired.

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

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

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

Business Combinations

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

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

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Impairment of Long-lived Assets

The Partnership reviews intangible assets and other long-lived assets in accordance with FASB ASC 360-10-05-4 Property Plant and Equipment topic, Impairment or Disposal of Long-Lived Assets subsection, for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. The Partnership determines whether the carrying values of such assets are recoverable over their remaining estimated lives through undiscounted future cash flow analysis. If such a review should indicate that the carrying amount of the assets is not recoverable, the Partnership will reduce the carrying amount of such assets to fair value.

Deferred Charges

Deferred charges represent the costs associated with the issuance of debt instruments and are amortized over the lives of the related debt instruments.

Advertising and Direct Mail Expenses

Advertising and direct mail costs are expensed as they are incurred. Advertising and direct mail expenses were $9.6 million, $8.4 million, and $7.2 million in 2010, 2009, and 2008, respectively and are recorded in delivery and branch expenses.

Customer Credit Balances

Customer credit balances represent payments received in advance from customers pursuant to a balanced payment plan (whereby customers pay on a fixed monthly basis) and the payments made have exceeded the charges for heating oil deliveries.

Environmental Costs

Costs associated with managing hazardous substances and pollution are expensed on a current basis. Accruals are made for costs associated with the remediation of environmental pollution when it becomes probable that a liability has been incurred and the amount can be reasonably estimated.

Insurance Reserves

The Partnership accrues for workers’ compensation, general liability and automobile claims not covered under its insurance policies and establishes estimates based upon actuarial assumptions as to what its ultimate liability will be for these claims.

Income Taxes

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

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

As most of the Partnership’s income is derived from its corporate subsidiaries, these financial statements reflect significant Federal and State income taxes. For corporate subsidiaries of the Partnership, a consolidated Federal income tax return is filed. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amount of assets and liabilities and their respective tax bases and operating loss carry-forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. A valuation allowance is recognized if, based on the weight of available evidence including historical tax losses, it is more likely than not that some or all of deferred tax assets will not be realized.

Sales, Use and Value Added Taxes

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

F-11

Derivatives and Hedging

The Financial Accounting Standards Board (“FASB”) ASC 815-10-05 Derivatives and Hedging topic established accounting and reporting standards requiring that derivative instruments be recorded at fair value and included in the consolidated balance sheet as assets or liabilities. To the extent derivative instruments designated as cash flow hedges are effective and the standard’s documentation requirements have been met, changes in fair value are recognized in other comprehensive income until the underlying hedged item is recognized in earnings. 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.

Weather Hedge Contract

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

Recent Accounting Pronouncements

In July 2010, FASB issued Accounting Standards Update (“ASU”) No. 2010-20 Receivables (Topic 310): Disclosures about the Credit Quality of Financing Receivables and the Allowance for Credit Losses. This standard requires companies to improve their disclosures about the credit quality of their financing receivables and the credit reserves held against them. The guidance covers trade accounts receivables, financing receivables, loans, loan syndications, factoring arrangements, and standby letters of credit. The Partnership is required to adopt this standard in the first quarter of fiscal 2011. The Partnership is currently assessing the impact of the disclosure requirements.

4) Quarterly Distribution of Available Cash

The Partnership agreement provides that beginning October 1, 2008, minimum quarterly distributions on the common units will start accruing at the rate of $0.0675 per quarter ($0.27 on an annual basis) in accordance with the Partnership agreement. There will be no distributions of available cash by us before February 2009. Thereafter, in general, the Partnership intends to distribute to its partners on a quarterly basis, all of its available cash, if any, in the manner described below. “Available cash” generally means, for any of its fiscal quarters, all cash on hand at the end of that quarter, less the amount of cash reserves that are necessary or appropriate in the reasonable discretion of the general partners to:

•

provide for the proper conduct of the Partnership’s business including acquisitions and debt payments;

•

comply with applicable law, any of its debt instruments or other agreements; or

•

provide funds for distributions to the common unitholders during the next four quarters, in some circumstances.

Available cash will generally be distributed as follows:

•

first, 100% to the common units, pro rata, until the Partnership distributes to each common unit the minimum quarterly distribution of $0.0675;

•

second, 100% to the common units, pro rata, until the Partnership distributes to each common unit any arrearages in payment of the minimum quarterly distribution on the common units for prior quarters;

•

third, 100% to the general partner units, pro rata, until the Partnership distributes to each general partner unit the minimum quarterly distribution of $0.0675;

•

fourth, 90% to the common units, pro rata, and 10% to the general partner units, pro rata (subject to the Management Incentive Plan), until the Partnership distributes to each common unit the first target distribution of $0.1125; and

•

thereafter, 80% to the common units, pro rata, and 20% to the general partner units, pro rata.

The revolving credit facility and the indenture for the 10.25% and 8.875% Senior Notes impose certain restrictions on the Partnership’s 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 availability of at least $40 million plus 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.

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5) Derivatives and Hedging—Disclosures and Fair Value Measurements

The Partnership uses derivative instruments such as futures, options, and swap agreements, in order to mitigate exposure to market risk associated with the purchase of home heating oil for price-protected customers, physical inventory on hand, inventory in transit and priced purchase commitments.

To hedge a substantial majority of the purchase price associated with heating oil gallons anticipated to be sold to its price-protected customers as of September 30, 2010, the Partnership bought 4.3 million gallons of physical inventory and had 0.6 million gallons of swap contracts to buy heating oil with a notional value of $1.4 million and a fair value of $(0.04) million; 34.2 million gallons of call options with a notional value of $85.0 million and a fair value of $4.9 million; 1.4 million gallons of put options with a notional value of $2.3 million and a fair value of $0.02 million and 58.4 million net gallons of synthetic calls with a notional value of $135.8 million and a fair value of $ 3.6 million. To hedge the inter-month differentials for our price-protected customers, its physical inventory on hand, and inventory in transit, the Partnership as of September 30, 2010 had 0.3 million gallons of future contracts to buy heating oil with a notional value of $0.6 million and a fair value of $0.03 million; 0.9 million gallons of future contracts to sell heating oil with a notional value of $2.0 million and a fair value of $(0.1) million; and 22.6 million gallons of swap contracts to sell heating oil with a notional value of $48.7 million and a fair value of $(3.3) million. To hedge a portion of its internal fuel usage, the Partnership as of September 30, 2010, had 1.4 million gallons of swap contracts to buy gasoline with a notional value of $2.8 million and a fair value of $0.2 million and 1.4 million gallons of swap contracts to buy diesel with a notional value of $3.1 million and a fair value of $0.2 million.

To hedge a substantial majority of the purchase price associated with heating oil gallons anticipated to be sold to its price-protected customers as of September 30, 2009, the Partnership had 4.3 million gallons of swap contracts to buy heating oil with a notional value of $7.8 million and a fair value of $0.5 million; 0.1 million gallons of future contracts to buy heating oil with a notional value of $0.1 million and a fair value of $0.02 million; 0.3 million gallons of future contracts to sell heating oil with a notional value of $0.4 million and a fair value of $(0.1) million; 85.0 million gallons of call options with a notional value of $176.3 million and a fair value of $16.5 million; 3.2 million gallons of put options with a notional value of $3.3 million and a fair value of $0.01 million and 12.1 million net gallons of synthetic calls with a notional value of $22.4 million and a fair value of $1.8 million. To hedge the inter-month differentials for our price-protected customers, its physical inventory on hand, and inventory in transit, the Partnership as of September 30, 2009 had 6.2 million gallons of future contracts to buy heating oil with a notional value of $16.5 million and a fair value of $(4.0) million; 12.5 million gallons of future contracts to sell heating oil with a notional value of $28.1 million and a fair value of $4.1 million; and 22.3 million gallons of swap contracts to sell heating oil with a notional value of $36.7 million and a fair value of $(5.4) million. To hedge a portion of its internal fuel usage, the Partnership as of September 30, 2009, had 1.5 million gallons of swap contracts to buy gasoline with a notional value of $2.1 million and a fair value of $0.7 million and 1.5 million gallons of swap contracts to buy diesel with a notional value of $2.4 million and a fair value of $0.4 million.

The Partnership’s derivative instruments are with the following counterparties: Cargill, Inc., Key Bank National Association, Bank of America, N.A., JPMorgan Chase Bank, NA, Societe Generale, Newedge USA, LLC, and Wachovia Bank, N.A. (Wells Fargo Bank, N.A.). The Partnership assesses counterparty credit risk and maintains master netting arrangements with its counterparties to help manage the risks, and records its derivative positions on a net basis. Based on its assessment, the Partnership considers counterparty credit risk to be low. At September 30, 2010, the aggregate cash posted as collateral in the normal course of business at counterparties was $0.02 million.

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

FASB ASC 820-10 Fair Value Measurements and Disclosures topic, established a three-tier fair value hierarchy, which classified the inputs used in measuring fair value. These tiers include: Level 1, defined as observable inputs such as quoted prices for identical instruments in active markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions. The Partnership’s Level 1 derivative assets and liabilities represent the fair value of commodity

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contracts used in its hedging activities that are identical and traded in active markets. The Partnership’s Level 2 derivative assets and liabilities represent the fair value of commodity contracts used in its hedging activities that are valued using either directly or indirectly observable inputs, whose nature, risk and class are similar. No significant transfers of assets or liabilities have been made into and out of the Level 1 or Level 2 tiers. All derivative instruments were non-trading positions. The market prices used to value the Partnership’s derivatives have been determined using the New York Mercantile Exchange (“NYMEX”) and independent third party prices that are reviewed for reasonableness.

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


(In thousands)					Fair Value Measurements at Reporting Date Using:
Derivatives Not Designated as Hedging Instruments Under FASB ASC 815-10	Balance Sheet Location	Total			Quoted Prices in Active Markets for Identical Assets Level 1			Significant Other Observable Inputs Level 2			Significant Unobservable Inputs Level 3
Asset Derivatives at September 30, 2010
Commodity contracts	Fair asset and fair liability value of derivative instruments	$	11,991		$	29		$	11,962		$	—
Commodity contracts	Long-term derivative assets included in the deferred charges and other assets, net balance		43			—			43

Commodity contract assets at September 30, 2010		$	12,034		$	29		$	12,005		$	—


Liability Derivatives at September 30, 2010
Commodity contracts	Fair liability and fair asset value of derivative instruments	$	(6,419	)	$	(101	)	$	(6,318	)	$	—

Commodity contract liabilities at September 30, 2010		$	(6,419	)	$	(101	)	$	(6,318	)	$	—


Asset Derivatives at September 30, 2009
Commodity contracts	Fair asset and fair liability value of derivative instruments	$	23,867		$	3,875		$	19,992		$	—
Commodity contracts	Long-term derivative assets included in the deferred charges and other assets, net balance		389			133			256

Commodity contract assets at September 30, 2009		$	24,256		$	4,008		$	20,248		$	—


Liability Derivatives at September 30, 2009
Commodity contracts	Fair liability and fair asset value of derivative instruments	$	(9,856	)	$	(3,986	)	$	(5,870	)	$	—

Commodity contract liabilities at September 30, 2009		$	(9,856	)	$	(3,986	)	$	(5,870	)	$	—

F-14


(In thousands)

The Effect of Derivative Instruments on the Statement of Operations
		Amount of (Gain) or Loss Recognized
Derivatives Not Designated as Hedging Instruments Under FASB ASC 815-10	Location of (Gain) or Loss Recognized in Income on Derivative	Twelve Months Ended September 30, 2010			Twelve Months Ended September 30, 2009			Twelve Months Ended September 30, 2008
Commodity contracts	Cost of product (a)	$	22,942		$	79,846		$	(10,591	)
Commodity contracts	(Increase) / decrease in the fair value of derivative instruments	$	(5,622	)	$	(13,690	)	$	25,467

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

6) Inventories

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


	September 30,
	2010		2009
Heating oil and other fuels	$	51,678	$	48,504
Fuel oil parts and equipment		15,056		14,132

	$	66,734	$	62,636

Heating oil and other fuel inventories were comprised of 24.0 million gallons and 28.5 million gallons on September 30, 2010 and September 30, 2009, respectively. The Partnership has market price based product supply contracts for approximately 217 million home heating oil gallons, that it expects to fully utilize to meet its requirements over the next twelve months.

During fiscal 2010, Global Companies, Sunoco Inc., NIC Holding Corp. (Northville Industries) and BP North America provided 19.6%, 12.0%, 11.2% and 11.1% respectively, of our product purchases. Aside from these four suppliers, no single supplier provided more than 10% of our product supply during fiscal 2010.

7) Property and Equipment

The components of property and equipment and their estimated useful lives were as follows (in thousands):


	September 30,
	2010		2009		Useful Estimated Lives
Land and land improvements	$	13,445	$	11,261		Land improvements - 30 years
Buildings and leasehold improvements		25,608		24,319		1 -40 years
Fleet and other equipment		41,454		38,444		1 -16 years
Tanks and equipment		11,117		9,920		8 -35 years
Furniture, fixtures and office equipment		54,870		51,325		3 -12 years

Total		146,494		135,269
Less accumulated depreciation		101,782		97,775

Property and equipment, net	$	44,712	$	37,494

Depreciation expense was $6.0 million, $6.2 million, and $7.2 million, for the fiscal years ended September 30, 2010, 2009, and 2008 respectively.

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8) Goodwill and Other Intangible Assets

Goodwill

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

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

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

The Partnership performed its annual goodwill impairment valuation in each of the periods ending August 31, 2010, 2009, and 2008, and it was determined based on each year’s analysis that there was no goodwill impairment.

The preparation of this analysis was based upon management’s estimates and assumptions, and future impairment calculations would be affected by actual results that are materially different from projected amounts. To provide for a sensitivity of the discount rates and transaction multiples used, ranges of high and low values are employed in the analysis, with the low values examined to ensure that a reasonably likely change in an assumption would not cause the Partnership to reach a different conclusion.

A summary of changes in the Partnership’s goodwill during the fiscal years ended September 30, 2010 and 2009 are as follows (in thousands):


Balance as of September 30, 2008	$	182,011
Fiscal year 2009 activity		931

Balance as of September 30, 2009		182,942
Fiscal year 2010 activity (Business Combinations see Note 11)		16,110

Balance as of September 30, 2010	$	199,052

Intangibles, net

Intangible assets subject to amortization consist of the following (in thousands):


	September 30, 2010						September 30, 2009
	Gross Carrying Amount		Accum. Amortization		Net		Gross Carrying Amount		Accum. Amortization		Net
Customer lists and other intangibles	$	252,385	$	193,491	$	58,894	$	204,426	$	183,958	$	20,468

Amortization expense for intangible assets was $9.5 million, $13.0 million, and $19.3 million, for the fiscal years ended September 30, 2010, 2009, and 2008, respectively. Total estimated annual amortization expense related to intangible assets subject to amortization, for the year ended September 30, 2011 and the four succeeding fiscal years ended September 30, is as follows (in thousands):


	Amount
2011	$	10,245
2012	$	5,878
2013	$	5,876
2014	$	5,800
2015	$	5,665

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9) Accrued Expenses and Other Current Liabilities

The components of accrued expenses and other current liabilities were as follows (in thousands):


	September 30,
	2010		2009
Accrued wages and benefits	$	16,135	$	17,043
Accrued workers’ compensation, general liability, auto claims and environmental		42,466		35,712
Other accrued expenses and other current liabilities		10,253		11,691

	$	68,854	$	64,446

10) Long-Term Debt and Bank Facility Borrowings

The Partnership’s debt at September 30, 2010 and 2009 is as follows (in thousands):


	At September 30, 2010				At September 30, 2009
	Carrying Amount		Estimated Fair Value (a)		Carrying Amount		Estimated Fair Value (a)
10.25% Senior Notes (b)	$	82,770	$	83,908	$	133,112	$	133,112
Revolving Credit Facility Borrowings (c)		—		—		—		—

Total debt	$	82,770	$	83,908	$	133,112	$	133,112

Total long-term portion of debt	$	82,770	$	83,908	$	133,112	$	133,112

(a)

Our fair value estimates of long-term debt are made at a specific point in time, based on relevant market information, open market quotations and information about the financial instrument. These estimates are subjective in nature and involve uncertainties and matters of significant judgment and therefore cannot be determined with precision. Changes in assumptions could significantly affect the estimates.

(b)

These notes mature in February 2013 and accrue interest at an annual rate of 10.25% requiring semi-annual interest payments on February 15 and August 15 of each year. The net premium on these notes were $0.3 million and $0.6 million at September 30, 2010 and 2009 respectively. These notes are redeemable at the option of the Partnership, in whole or in part, from time to time by payment of a premium. Under the terms of the indenture dated as of April 28, 2006, these notes permit restricted payments of $22 million, permit the Partnership to incur debt up to $60 million for acquisitions without passing certain financial tests, and restrict the proceeds of asset sales from being invested in current assets for purposes of the “asset sale” covenant.

In fiscal year September 30, 2010, the Partnership repurchased in total $50 million (face value) of these notes and recorded a total loss of $1.1 million.

On November 16, 2010 the 10.25% Senior Notes were called at a redemption price of 101.708% plus any accrued but unpaid interest thereon with a redemption date of December 20, 2010. The 10.25% Senior Notes will be repaid with the proceeds of the Partnership’s Rule 144A 8.875% Senior Notes due 2017. The 8.875% Senior Notes require semi-annual interest payments on June 1 and December 1 of each year and have similar covenants as the 10.25% Senior Notes described above.

(c)

In July 2009, the Partnership entered into an amended and restated asset based revolving credit facility agreement with a bank syndication comprised of nine banks. This amended facility, that extends to July 2012, provides the Partnership with the ability to borrow up to $240 million ($290 million during the heating season from November to April each year) for working capital purposes (subject to certain borrowing base limitations and coverage ratios), including the issuance of up to $100 million in letters of credit. The Partnership can increase the facility size by $50 million without the consent of the bank group. The bank group is not obligated to fund the $50 million increase. If the bank group elects not to fund the increase, the Partnership can add additional lenders to the group, with the consent of the Agent, which shall not be unreasonably withheld. The interest rate is LIBOR plus; 3.50% (if availability, as defined in the revolving credit facility agreement is greater than or equal to $150 million), or 3.75% (if availability is greater than $75 million but less than $150 million), or 4.00% (if availability is less than or equal to $75 million). The unused commitment fee is 0.75%

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

F-17

In May 2010, the Partnership entered into a second amendment to the amended and restated asset based revolving credit facility agreement that updated the capitalized defined term.

In November 2010, the Partnership entered into a third amendment to the amended and restated asset based revolving credit facility agreement that updated the capitalized defined term.

At September 30, 2010 and 2009, no amount was outstanding under the revolving credit facility and $42.3 million and $40.9 million of letters of credit were issued, respectively.

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

Under the terms of the revolving credit facility, the Partnership must maintain at all times either availability (borrowing base less amounts borrowed and letters of credit issued) of $43.5 million or a fixed charge coverage ratio (as defined in the credit agreement) of not less than 1.10x. In addition, the Partnership must have availability of at least $40 million plus and maintain a fixed charge coverage ratio of 1.15x in order to make its minimum quarterly distributions of $0.0675 per unit, and 1.25x to make any distributions in excess of the minimum quarterly distributions. No inter-company dividends or distributions can be made (including those needed to pay interest or principle on the 10.25% Senior Notes) if the relevant covenant described above has not been met.

As of September 30, 2010, availability was $104.8 million, the restricted net assets totaled approximately $356 million and the Partnership was in compliance with the fixed charge coverage ratio. Restricted net assets are assets of the Partnership in its subsidiaries that any distribution or transfer of which to Star Gas Partners, L.P. from the subsidiary, are subject to limitations under its revolving credit facility. As of September 30, 2009, availability was $194.4 million, the restricted net assets totaled approximately $432 million and the Partnership was in compliance with the fixed charge coverage ratio.

As of September 30, 2010, the maturities including working capital borrowings during fiscal years ending September 30, are set forth in the following table (in thousands):


2011	$	—
2012	$	—
2013	$	82,770	(d)
2014	$	—
2015	$	—
Thereafter	$	—

(d)	This amount will be repaid on December 20, 2010 with a portion of the proceeds from the Partnership’s 8.875% $125.0 million Senior Notes issued on November 16, 2010.

11) Business Combinations

During fiscal 2010, the Partnership acquired five retail heating oil dealers. The aggregate purchase price was approximately $68.8 million, including working capital of $4.2 million.

During fiscal 2009, the Partnership acquired one retail heating oil dealer. The aggregate purchase price was approximately $4.0 million, reduced by working capital credits of $0.7 million.

During fiscal 2008, the Partnership acquired seven retail heating oil dealers. The aggregate purchase price was approximately $2.6 million, reduced by $0.7 million of working capital credits.

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The following table summarizes the preliminary fair values and purchase price allocation at the acquisition dates, of the assets acquired and liabilities assumed related to acquisitions made as of September 30, 2010. These values are preliminary pending final valuation of intangibles, certain deferred tax assets and certain working capital items.


(in thousands)	As of Acquisition Date
Trade accounts receivable (a)	$	12,377
Inventories		2,086
Other current assets		5,567
Property and equipment		7,642
Customer lists and other intangibles		40,220
Trade names		7,740
Current liabilities		(15,870	)
Long-term deferred tax liabilities		(7,091	)

Total net identifiable assets acquired	$	52,671

Total consideration transferred	$	68,781
Less: Total net identifiable assets acquired		52,671

Goodwill	$	16,110

(a)	The gross contractual receivable amount is $15.0 million, and the best estimate at the acquisition date of the contractual cash flows not expected to be collected is $2.6 million.

The total costs related to these acquisitions were included in the Consolidated Statement of Operations under general and administrative expenses and were $0.7 million.

Of the $16.1 million of goodwill relating to these acquisitions, $1.8 million is deductible for income tax purposes. Goodwill is being derived from the ability of the businesses to regenerate customers and to a lesser extent, certain synergies.

Except for the acquisition of the Champion Energy Corporation (“Champion”), the other acquisitions noted above, individually and in the aggregate were not material to the Partnership. Each acquired company’s operating results are included in the Partnership’s consolidated financial statements starting on the date of acquisition. Customer lists, other intangibles and trade names are amortized on a straight-line basis over seven to ten years.

Included in the figures above is the acquisition of Champion. On May 10, 2010, the Partnership entered into an Equity Purchase Agreement pursuant to which it acquired 100% of the capital stock of Champion for a purchase price of approximately $50.1 million plus working capital of approximately $7.5 million (net of cash acquired), payable in cash. The business reason for this acquisition is that Champion is an excellent fit for the Partnership, as it serves over 45,000 home heating oil customers in markets in which the Partnership currently operates, and sold 35.2 million gallons of residential home heating oil, 4.1 million gallons of commercial home heating oil and 8.9 million gallons of other petroleum products for the twelve months ending June 30, 2009.

A remediation liability of $4.1 million has been recognized as of the acquisition date in connection with Champion. The remediation liability was determined by management and primarily represents the costs to remediate a Champion facility. An estimated range of the remediation costs is expected to be between $1.8 million and $5.9 million, with $4.1 million representing the fair value of the expected total cost as of the acquisition date.

Sales and net loss of Champion for fiscal 2010 totaled $25.1 million and $(2.8) million, respectively for the period from the acquisition date through September 30, 2010.

The following table provides unaudited pro forma results of operations as if the Champion acquisition had occurred on October 1, 2008. The unaudited pro forma results were prepared using Champion’s current and prior year financial information, reflecting certain adjustments related to the acquisition, such as the elimination of select nonrecurring charges, and changes to administrative, interest and depreciation and amortization expenses. These pro forma adjustments do not include any potential synergies related to combining the businesses. Accordingly, such pro forma operating results were prepared for comparative purposes only and do not purport to be indicative of what would have occurred had the acquisition been made as of October 1, 2008 or of results that may occur in the future.

F-19


	September 30,
(in thousands)	2010		2009
Net sales	$	1,328,786	$	1,331,159
Net income		34,135	$	134,801

12) Employee Benefit Plans

Defined Contribution Plans

The Partnership has a 401(k) plan which covers eligible non-union and union employees. Subject to IRS limitations, the 401(k) plan provides for each participant to contribute from 0% to 60% 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. The Partnership’s aggregate contributions to the 401(k) plan during fiscal 2010, 2009, and 2008, were $4.4 million, $4.2 million, and $4.2 million, respectively.

Long-Term Management Incentive Compensation Plan

The Partnership has a Long-Term Management Incentive Plan (see Item 11. Executive Compensation). The long-term compensation structure is intended to align the employee’s performance with the long-term performance of our unitholders. Under the Plan, employees who participate shall be entitled to receive a pro rata share of an amount in cash equal to:

•

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 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 Partnership is not required to reimburse Kestrel Heat for amounts payable pursuant to the Plan.

The Partnership distributed approximately $116,000 in Incentive Distributions during fiscal 2010, of which named executive officers received approximately $40,000 under its long-term incentive plan. . 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.

F-20

Union-Administered Pension Plans

The Partnership’s contributions to union-administered pension plans were $7.7 million for fiscal 2010, $7.2 million for fiscal 2009, and $6.9 million for fiscal 2008. Some of these union administered pension plans have significant unfunded liabilities, a portion of which could be assessed to the Partnership should we withdraw from these plans. The Partnership does not expect to withdraw from these plans.

Defined Benefit Plans

The Partnership accounts for its two frozen defined benefit pension plans (“the Plan”) in accordance with FASB ASC 715-10-05 Compensation-Retirement Benefits topic. The Partnership has no post-retirement benefit plans.

F-21

The following table provides the net periodic benefit cost for the period, a reconciliation of the changes in the Plan assets, projected benefit obligations, and the amounts recognized in other comprehensive income and accumulated other comprehensive income at the dates indicated using a measurement date of September 30:


(in thousands) Debit / (Credit)	Net Periodic Pension Cost in Income Statement			Cash			Fair Value of Pension Plan Assets			Projected Benefit Obligation			Other Comprehensive Income			Gross Pension Related Accumulated Other Comprehensive Income
Fiscal Year 2008
Beginning balance							$	49,218		$	(59,627	)				$	16,435

Interest cost		3,533									(3,533	)
Actual return on plan assets		7,815						(7,815	)
Employer contributions					(1,536	)		1,536
Benefit payments								(4,282	)		4,282
Investment and other expenses		(437	)								437
Difference between actual and expected return on plan assets		(11,282	)											11,282
Anticipated expenses		246									(246	)
Actuarial gain											7,339			(7,339	)
Amortization of unrecognized net actuarial loss		997												(997	)

Annual cost/change	$	872		$	(1,536	)		(10,561	)		8,279		$	2,946			2,946

Ending balance							$	38,657		$	(51,348	)				$	19,381

Funded status at the end of the year										$	(12,691	)

Fiscal Year 2009
Interest cost		3,647									(3,647	)
Actual return on plan assets		(1,453	)					1,453
Employer contributions					(1,970	)		1,970
Benefit payments								(4,493	)		4,493
Investment and other expenses		(361	)								361
Difference between actual and expected return on plan assets		(1,227	)											1,227
Anticipated expenses		193									(193	)
Actuarial loss											(11,931	)		11,931
Amortization of unrecognized net actuarial loss		1,304												(1,304	)

Annual cost/change	$	2,103		$	(1,970	)		(1,070	)		(10,917	)	$	11,854			11,854

Ending balance							$	37,587		$	(62,265	)				$	31,235

Funded status at the end of the year										$	(24,678	)

Fiscal Year 2010
Interest cost		3,250									(3,250	)
Actual return on plan assets		(2,666	)					2,666
Employer contributions					(13,107	)		13,107
Benefit payments								(4,037	)		4,037
Investment and other expenses		(460	)								460
Difference between actual and expected return on plan assets		276												(276	)
Anticipated expenses		188									(188	)
Actuarial loss											(4,716	)		4,716
Amortization of unrecognized net actuarial loss		2,463												(2,463	)

Annual cost/change	$	3,051		$	(13,107	)		11,736			(3,657	)	$	1,977			1,977

Ending balance							$	49,323		$	(65,922	)				$	33,212

Funded status at the end of the year										$	(16,599	)

F-22

At September 30, 2010 and 2009, $16.6 million and $24.7 million respectively, were included in the other long-term liabilities amount on the balance sheet.

The $33.2 million net actuarial loss balance for the two frozen defined benefit pension plans in accumulated other comprehensive income will be recognized and amortized into net periodic pension costs as an actuarial loss in future years. The estimated amount that will be amortized from accumulated other comprehensive income into net periodic pension cost over the next fiscal year is $2.8 million.


	Years Ended September 30,
	2010			2009			2008
Weighted-Average Assumptions Used in the Measurement of the Partnership’s Benefit Obligation as of the period indicated
Discount rate		4.70	%		5.40	%		7.60	%
Expected return on plan assets		7.75	%		8.25	%		8.25	%
Rate of compensation increase		N/A			N/A			N/A

The expected return on plan assets is determined based on the expected long-term rate of return on plan assets and the market-related value of plan assets determined using fair value.

The Partnership’s expected long-term rate of return on plan assets is updated at least annually, taking into consideration our asset allocation, historical returns on the types of assets held, and the current economic environment. Based on these factors, beginning in fiscal year 2011, the Partnership expects its pension assets will earn an average of 7.75% per annum.

The discount rate used to determine net periodic pension expense was 5.4% in 2010, 7.6% in 2009 and 6.2% in 2008. The discount rate used by the Partnership in determining pension expense and pension obligations reflects 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 projected future benefit payments.

The Plan’s objectives are to have the ability to pay benefit and expense obligations when due, to maintain the funded ratio of the Plan, to maximize return within reasonable and prudent levels of risk in order to minimize contributions and charges to the profit and loss statement, and to control costs of administering the Plan and managing the investments of the Plan. The strategic asset allocation of the Plan (currently 60% domestic fixed income, 30% domestic equities and 10% international equities) is based on a long-term perspective and the premise that the Plan can tolerate some interim fluctuations in market value and rates of return in order to achieve long-term objectives.

The fair values and percentage of the Partnership’s pension plan assets by asset category are as follows:


(in thousands)	Level 1		Level 2		Level 3		Total		Concentration Percentage
Asset Category at September 30, 2010
Corporate and U.S. government bond fund (1)		27,014		—		—		27,014		54	%
U.S. government and agency debt securities (1)		2,260		—		—		2,260		5	%
U.S. large-cap equity (1)		14,791		—		—		14,791		30	%
International equity (1)		4,958		—		—		4,958		10	%
Cash and cash equivalents (2)		—		300		—		300		1	%

Total		49,023		300		—		49,323		100	%

(1)	Represent investments in Vanguard funds that seek to replicate the asset category description.

(2)	Represent investments in a diversified money market fund.

Partnership expects to make pension contributions of approximately $3.2 million in fiscal 2011.

Expected benefit payments over each of the next five years will total approximately $4.4 million per year. Expected benefit payments for the five years thereafter will aggregate approximately $21.5 million.

F-23

13) Income Taxes

Income tax expense is comprised of the following for the indicated periods (in thousands):


	Years Ended September 30,
	2010		2009			2008
Current:
Federal	$	726	$	2,068		$	380
State		1,575		1,690			186
Deferred		13,331		(61,355	)		—

	$	15,632	$	(57,597	)	$	566

The provision for income taxes differs from income taxes computed at the Federal statutory rate as a result of the following:


	Years Ended September 30,
	2010			2009			2008
Income from continuing operations before taxes	$	43,952		$	73,441		$	(12,842	)
Tax at Federal statutory rate		15,383			25,704			(4,495	)
Less impact of Partnership income or loss not subject to federal income taxes		1,239			(2,447	)		1,043
State taxes net of federal benefit		3,087			4,319			121
Permanent Differences		(44	)		52			368
Change in valuation allowance		(3,928	)		(86,445	)		3,603
Change in unrecognized tax benefit and other		(105	)		1,220			(74	)

Benefit / provision for income taxes per income statement	$	15,632		$	(57,597	)	$	566

The components of the net deferred taxes and the related valuation allowance for the years ended September 30, 2010 and September 30, 2009 using current tax rates are as follows (in thousands):


	Years Ended September 30,
	2010		2009
Deferred Tax Assets:
Net operating loss carryforwards	$	19,958	$	25,341
Vacation accrual		2,624		2,479
Pension accrual		6,889		10,241
Allowance for bad debts		2,909		2,601
Intangibles		—		5,723
Fair value of derivative instruments		2,016		4,349
Insurance accrual		15,530		14,432
Inventory		968		2,280
Alternative minimum tax credit carryforward		3,077		1,630
Other, net		2,692		1,639

Total deferred tax assets		56,663		70,715
Valuation allowance		—		(3,928	)

Net deferred tax assets	$	56,663	$	66,787

Deferred Tax Liabilities:
Property and equipment	$	927	$	387
Intangibles		8,937		—

Total deferred tax liabilities	$	9,864	$	387

Net deferred taxes	$	46,799	$	66,400

F-24

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.

In June 2007, the Partnership amended its Amended and Restated Unit Purchase Rights Agreement dated as of July 20, 2006 in order to protect the Partnership’s Net Operating Loss Carry forwards (“NOLs”) for Federal income tax purposes by adding provisions which would have the effect of deterring any person or group from acquiring more than 5% (reduced from 15% prior to the amendment) of the Partnership’s issued and outstanding common units. The amendment also discouraged existing 5% or greater unitholders (including the General Partner) from acquiring additional common units equal to 1% or more of the outstanding common units. A person or group that acquires units in excess of these amounts would be subject to substantial dilution under the Rights Agreement. In May 2009, the Partnership entered into a further amendment to its Amended and Restated Unit Purchase Rights Agreement to amend the definition of acquiring person to restore the acquisition threshold to 15% of the outstanding common units.

FASB ASC 740-10-05-6 Income Taxes topic, Tax Position subtopic, provides financial statement accounting guidance for uncertainty in income taxes and tax positions taken or expected to be taken in a tax return.

At September 30, 2010, we had unrecognized income tax benefits totaling $2.2 million including related accrued interest and penalties of $0.2 million. These unrecognized tax benefits are primarily the result of Federal tax uncertainties. If recognized, these tax benefits and related interest and penalties would be recorded as a benefit to the effective tax rate.

Tax Uncertainties (in thousands)


Balance at September 30, 2009	$	1,393
Additions based on tax positions related to the current year		499
Additions for tax positions of prior years		480
Reduction for tax positions of prior years		—
Reductions due to lapse in statue of limitations/settlements		(137	)

Balance at September 30, 2010		2,235

We believe that the total liability for unrecognized tax benefits will not materially change during the next 12 months ending September 30, 2011. Our continuing practice is to recognize interest and penalties related to income tax matters as a component of income tax expense.

We file U.S. Federal income tax returns and various state and local returns. A number of years may elapse before an uncertain tax position is audited and finally resolved. For our Federal income tax returns we have four tax years subject to examination. In our major state tax jurisdictions of New York, Connecticut, Pennsylvania and New Jersey, we have four, four, five, and five tax years, respectively, that are subject to examination. While it is often difficult to predict the final outcome or the timing of resolution of any particular uncertain tax position, based on our assessment of many factors including past experience and interpretation of tax law, we believe that our provision for income taxes reflect the most probable outcome. This assessment relies on estimates and assumptions and may involve a series of complex judgments about future events.

F-25

14) Lease Commitments

The Partnership has entered into certain operating leases for office space, trucks and other equipment. The future minimum rental commitments at September 30, 2010 under operating leases having an initial or remaining non-cancelable term of one year or more are as follows (in thousands):


2011	$	10,541
2012		10,083
2013		9,157
2014		8,110
2015		6,303
Thereafter		11,784

Total future minimum lease payments	$	55,978

Rent expense for the fiscal years ended September 30, 2010, 2009, and 2008, was $13.3 million, $15.8 million, and $13.9 million, respectively.

15) Supplemental Disclosure of Cash Flow Information


	Years Ended September 30,
(in thousands)	2010		2009		2008
Cash paid during the period for:
Income taxes, net	$	2,061	$	2,091	$	2,241
Interest	$	14,836	$	18,221	$	20,651
Non-cash financing activities:
Decrease in interest expense—amortization of net debt premium	$	132	$	226	$	188
Decrease in net debt premium attributable to redemption of debt	$	203	$	172	$	—
Decrease in deferred charges attributable to revolving credit facility amendment	$	—	$	322	$	—

16) Commitments and Contingencies

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

F-26

17) Earnings Per Limited Partner Units

The following table presents the net income allocation and per unit data in accordance with FASB ASC 260-10-45-60 Basic and Diluted Earnings per Share topic, Participating Securities and the Two-Class Method subtopic (EITF 03-06):


Basic and Diluted Earnings Per Limited Partner: (in thousands, except per unit data)	Years Ended September 30,
	2010		2009		2008
Net income (loss)	$	28,320	$	131,038	$	(13,408	)
Less General Partners’ interest in net income (loss)		128		561		(57	)

Net income (loss) available to limited partners		28,192		130,477		(13,351	)
Less dilutive impact of theoretical distribution of earnings under FASB ASC 260-10-45-60 *		1,258		22,252		—

Limited Partner’s interest in net income (loss) under FASB ASC 260-10-45-60	$	26,934	$	108,225	$	(13,351	)

Per unit data:
Basic and diluted net income (loss) available to limited partners	$	0.40	$	1.72	$	(0.18	)
Less dilutive impact of theoretical distribution of earnings under FASB ASC 260-10-45-60 *		0.02		0.29		—

Limited Partner’s interest in net income (loss) under FASB ASC 260-10-45-60	$	0.38	$	1.43	$	(0.18	)

Weighted average number of Limited Partner units outstanding		70,019		75,738		75,774

In any accounting period where the Partnership’s aggregate net income exceeds its aggregate distribution for such period, the Partnership is required as per FASB ASC 260-10-45-60 to present net income per limited partner unit as if all of the earnings for the period were distributed, based on the contractual participation rights of the security to share in earnings, regardless of whether those earnings would actually be distributed during a particular period from an economic or practical perspective. This allocation does not impact the Partnership’s overall net income or other financial results.

F-27

18) Selected Quarterly Financial Data (unaudited)

The seasonal nature of the Partnership’s business results in the sale by the Partnership of approximately 30% of its volume in the first fiscal quarter and 45% of its volume in the second fiscal quarter of each year. The Partnership generally realizes net income in both of these quarters and net losses during the quarters ending June and September.


	Three Months Ended
(in thousands - except per unit data)	Dec. 31, 2009			Mar. 31, 2010		Jun. 30, 2010			Sep. 30, 2010			Total
Sales	$	348,819		$	551,732	$	176,761		$	135,464		$	1,212,776
Gross profit for product, installation and service		88,632			147,502		43,350			29,245			308,729
Operating income (loss)		26,614			75,125		(13,881	)		(29,274	)		58,584
Income (loss) before income taxes		22,082			70,371		(16,223	)		(32,278	)		43,952
Net income (loss)		12,005			40,535		(9,991	)		(14,229	)		28,320
Limited Partner interest in net income (loss)		11,951			40,348		(9,944	)		(14,163	)		28,192
Net income (loss) per Limited Partner unit:
Basic and diluted (a)	$	0.15		$	0.48	$	(0.14	)	$	(0.21	)	$	0.38

	Three Months Ended
(in thousands - except per unit data)	Dec. 31, 2008			Mar. 31, 2009		Jun. 30, 2009			Sep. 30, 2009			Total
Sales	$	402,850		$	520,500	$	167,669		$	115,794		$	1,206,813
Gross profit for product, installation and service		104,362			152,234		45,122			29,340			331,058
Operating income (loss)		(7,366	)		110,880		956			(24,348	)		80,122
Income (loss) before income taxes		(8,363	)		113,369		(2,422	)		(29,143	)		73,441
Net income (loss)		(8,011	)		108,667		(1,924	)		32,306			131,038
Limited Partner interest in net income (loss)		(7,976	)		108,201		(1,916	)		32,168			130,477
Net income (loss) per Limited Partner unit:
Basic and diluted (a)	$	(0.11	)	$	1.17	$	(0.03	)	$	0.36		$	1.43

(a)	The sum of the quarters do not add-up to the total due to the weighting of Limited Partner Units outstanding, rounding or the theoretical effects of FASB ASC 260-10-45-60 to Master Limited Partners earnings per unit.

19) Subsequent Events

Quarterly Distribution Declared

On October 26, 2010, the Partnership declared a quarterly distribution of $0.0725 per unit on all common and general partner units, for unitholders of record on November 4, 2010, to be paid on November 12, 2010. The total distribution paid was approximately $4.9 million.

Rule 144A Offering of Senior Notes due 2017

On November 10, 2010, the Partnership priced its Rule 144A offering of Senior Notes due 2017 and closed on it on November 16, 2010. The notes will accrue interest at a rate of 8.875% and were priced at 99.350%, for total gross proceeds of $124.2 million. The proceeds will be used to redeem all of the remaining $82.5 million in face amount of 10.25% Senior Notes due 2013 and for general partnership purposes.

Election to Redeem 10.25% Senior Notes due 2013

On November 16, 2010, the Partnership gave notice to Union Bank, N.A, the Trustee of the Issuers’ 10.25% Senior Notes due 2013 (the “Senior Notes”) of the Issuers’ election to redeem (the “Redemption”) all of the remaining $82.5 million in face amount of Senior Notes at a redemption price of 101.708% plus any accrued but unpaid interest thereon with a redemption date of December 20, 2010. The Trustee will also serve as the Paying Agent for the Redemption.

F-28

Schedule I

STAR GAS PARTNERS, L.P. (PARENT COMPANY)

CONDENSED FINANCIAL INFORMATION OF REGISTRANT


(in thousands)	Sept. 30, 2010		Sept. 30, 2009
Balance Sheets

ASSETS
Current assets
Cash and cash equivalents	$	230	$	46
Prepaid expenses and other current assets		1,039		1,471

Total current assets		1,269		1,517

Investment in subsidiaries (a)		365,592		442,146
Deferred charges and other assets, net		589		1,404

Total Assets	$	367,450	$	445,067

LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities
Accrued expenses	$	2,300	$	3,002

Total current liabilities		2,300		3,002

Long-term debt (b)		82,770		133,112
Other long-term liabilities		2,469		2,619
Partners’ capital		279,911		306,334

Total Liabilities and Partners’ Capital	$	367,450	$	445,067

(a)	Investments in Star Acquisitions, Inc. and subsidiaries are recorded in accordance with the equity method of accounting.

(b)

Scheduled principal repayments of long-term debt during each of the next five fiscal years ending September 30, are as follows: 2011—$0; 2012—$0; 2013—$82,770 ($82,499 excluding discounts and premiums) due February 2013; 2014—$0; 2015—$0; thereafter $0. This amount will be repaid on December 20, 2010 with a portion of the proceeds from the Partnership’s 8.875% $125.0 million Senior Notes issued on November 16, 2010.

F-29

STAR GAS PARTNERS, L.P. (PARENT COMPANY)

CONDENSED FINANCIAL INFORMATION OF REGISTRANT


	Years Ended September 30,
(in thousands)	2010			2009			2008
Statements of Operations
Revenues	$	—		$	—		$	—
General and administrative expenses		2,231			2,592			2,371

Operating loss		(2,231	)		(2,592	)		(2,371	)
Net interest expense		(10,299	)		(14,800	)		(17,512	)
Amortization of debt issuance costs		(336	)		(444	)		(534	)
Gain (loss) on redemption of debt		(1,132	)		9,706			—

Loss from continuing operations		(13,998	)		(8,130	)		(20,417	)
Income (loss) from discontinued operations, net of income taxes		—			—			—
Gain (loss) on sale of discontinued operations, net of income taxes		—			—			—

Net income (loss) before equity income (loss)		(13,998	)		(8,130	)		(20,417	)
Equity income of Star Acquisitions, Inc. and subs		42,426			139,168			7,009

Net income (loss)	$	28,428		$	131,038		$	(13,408	)

F-30

STAR GAS PARTNERS, L.P. (PARENT COMPANY)

CONDENSED FINANCIAL INFORMATION OF REGISTRANT


	Years Ended September 30,
(in thousands)	2010			2009			2008
Statements of Cash Flows

Cash flows provided by operating activities:
Net cash provided by (used in) operating activities (a)	$	104,625		$	48,013		$	(418	)


Cash flows provided by (used in) investing activities:

Net cash provided by (used in) investing activities		—			—			—


Cash flows provided by (used in) financing activities:
Repayment of debt		(50,854	)		(30,230	)		—
Distributions		(20,353	)		(15,411	)
Unit repurchase		(33,234	)		(2,336	)

Net cash provided by (used in) financing activities		(104,441	)		(47,977	)		—

Net increase (decrease) in cash		184			36			(418	)
Cash and cash equivalents at beginning of period		46			10			428

Cash and cash equivalents at end of period	$	230		$	46		$	10

(a) Includes distributions from subsidiaries	$	117,310		$	65,164		$	20,487

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Schedule II

STAR GAS PARTNERS, L.P. AND SUBSIDIARIES

VALUATION AND QUALIFYING ACCOUNTS

Years Ended September 30, 2010, 2009 and 2008

(in thousands)


Year	Description	Balance at Beginning of Year		Charged to Costs & Expenses		Other Changes Add (Deduct)			Balance at End of Year
2010	Allowance for doubtful accounts	$	6,267	$	5,279	$	(6,103	) ^(a)	$	5,443
2009	Allowance for doubtful accounts	$	10,821	$	10,310	$	(14,864	) ^(a)	$	6,267
2008	Allowance for doubtful accounts	$	7,645	$	11,961	$	(8,785	) ^(a)	$	10,821

^(a)	Bad debts written off (net of recoveries).

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