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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, 2011	
OR
 
¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934	
 
    	For the transition period from              to             	
Commission File Number: 001-14129

STAR GAS PARTNERS, L.P.
(Exact name of registrant as specified in its charter)

 
 	 	 	
Delaware	 	06-1437793	
(State or other jurisdiction of incorporation or organization)	 	(I.R.S. Employer Identification No.)	
 	 	
2187 Atlantic Street, Stamford, Connecticut	 	06902	
(Address of principal executive office)	 	(Zip Code)	
(203) 328-7310
(Registrant’s 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   x     No   ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.     ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, 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 the registrant’s common units held by non-affiliates on March 31, 2011 was approximately $382,342,000. As of November 30, 2011, the registrant had 64,528,038 common units outstanding.
Documents Incorporated by Reference: None

 

Table of Contents
STAR GAS PARTNERS, L.P.
2011 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	  	 	17	  	
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	  	 	22	  	
Item 7A.	  	Quantitative and Qualitative Disclosures about Market Risk	  	 	43	  	
Item 8.	  	Financial Statements and Supplementary Data	  	 	43	  	
Item 9.	  	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	  	 	43	  	
Item 9A.	  	Controls and Procedures	  	 	43	  	
Item 9B.	  	Other Information	  	 	44	  	
 	 	 	
 	  	PART III	  	 	 	 	
 	 	 	
Item 10.	  	Directors and Executive Officers of the Registrant	  	 	44	  	
Item 11.	  	Executive Compensation	  	 	48	  	
Item 12.	  	Security Ownership of Certain Beneficial Owners and Management	  	 	58	  	
Item 13.	  	Certain Relationships and Related Transactions	  	 	58	  	
Item 14.	  	Principal Accounting Fees and Services	  	 	59	  	
 	 	 	
 	  	PART IV	  	 	 	 	
Item 15.	  	Exhibits and Financial Statement Schedules	  	 	60	  	
 
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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 the products that we sell, the consumption patterns of our customers, our ability to obtain satisfactory gross profit margins, our ability to obtain new customers and retain existing customers, our ability to make strategic acquisitions, the impact of litigation, our ability to contract for our current and future supply needs, natural gas conversions, future union relations and the outcome of current and future union negotiations, the impact of current and future governmental regulations, including environmental, health, and safety regulations, the ability to attract and retain employees, customer credit worthiness, counterparty credit worthiness, marketing plans, general economic conditions and new technology. All statements other than statements of historical facts included in this Report including, without limitation, the statements under “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and elsewhere herein, are forward-looking statements. Without limiting the foregoing, the words “believe,” “anticipate,” “plan,” “expect,” “seek,” “estimate,” and similar expressions are intended to identify forward-looking statements. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to be correct and actual results may differ materially from those projected as a result of certain risks and uncertainties. These risks and uncertainties include, but are not limited to, those set forth under the heading “Risk Factors” and “Business Strategy.” 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 and propane distributor and services provider with one reportable operating segment that principally provides services to residential and commercial customers to heat their homes and buildings. Star Gas Partners is a Delaware limited partnership, which at November 30, 2011, had outstanding 64.5 million common units (NYSE: “SGU”) representing a 99.50% limited partner interest in Star Gas Partners, and 0.3 million general partner units, representing a 0.50% 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, all of which are corporations subject to Federal and state income taxes. At December 31, 2011, we estimate that our Federal Net Operating Loss carryforwards (“NOLs”) will be $12.8 million subject to annual limitations of between $1.0 million and $2.2 million that can be used. As we have almost fully exhausted our Federal NOLs, the amount of cash taxes that our subsidiaries will pay going forward will increase significantly in future years, which will reduce the annual amount of cash available for distribution to unitholders.	
 
 	•	 	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 $125.0 million 8.875% Senior Notes (excluding discounts), which are due in December 2017, that we sometimes refer to in this Report as the notes or the senior notes. 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 10 of the Notes to the Consolidated Financial Statements - 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.
 
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Partnership structure
The following chart summarizes our partnership structure as of September 30, 2011. Other than Star Gas Partners, L.P. all other entities in this structure are taxable as corporations for Federal and state income tax purposes.

Business Overview
As of September 30, 2011, we sold home heating oil and propane to approximately 407,000 full service residential and commercial customers. We believe we are the largest retail distributor of home heating oil in the United States, based upon sales volume. We also sell home heating oil, gasoline and diesel fuel to approximately 39,000 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 11,500 customers. During fiscal 2011, total sales were comprised of approximately 79% from sales of home heating oil and propane; 13% 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 business and are intended to maximize customer satisfaction and loyalty.
We conduct our business through an operating subsidiary, Petro Holdings, Inc., and its subsidiaries, 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 home heating oil customers, including a variable price (market based) option and a price-protected option, the latter of which either sets the maximum price or a fixed price that a customer will pay. Approximately 97% of our deliveries for our full service residential and commercial home heating oil and propane 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 and propane deliveries and service billings are paid for in a series of equal monthly installments. We utilize derivative instruments in order to hedge a substantial majority of the home heating oil volume we expect to sell to price-protected customers that have renewed their price-protected plans, mitigating our exposure to changing commodity prices. We also use derivative instruments as a hedge against our home heating oil physical inventory and home heating oil priced purchase commitments. Our size gives us the ability to realize economies of scale and the ability to provide consistent, strong customer service.
 
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Currently, we have heating oil and propane customers in the following states, regions and counties:

Maine
York
 
New Hampshire
Rockingham
Strafford
 
Vermont
Bennington (1)
Rutland (1)
 
Massachusetts
Barnstable
Berkshire (1)
Bristol
Essex
Middlesex
Norfolk
Plymouth
Suffolk
Worcester
 
Rhode Island
Bristol
Kent
Newport
Providence
Washington
 
Connecticut
Fairfield
Hartford
Litchfield
Middlesex
New Haven
New London
Tolland
Windham	  	New York
Albany (1)
Bronx
Columbia (1)
Dutchess
Essex (1)
Franklin (1)
Fulton (1)
Greene (1)
Hamilton (1)
Kings
Montgomery (1)
Nassau
New York
Onondaga (1)
Orange
Putnam
Queens
Rensselaer (1)
Richmond
Saratoga (1)
Schenectady (1)
Schoharie (1)
Suffolk
Ulster
Warren (1)
Washington (1)
Westchester	  	New Jersey
Bergen
Burlington
Camden
Essex
Gloucester
Hudson
Hunterdon
Mercer
Middlesex
Monmouth
Morris
Ocean
Passaic
Salem
Somerset
Sussex
Union
Warren
 
Pennsylvania
Berks
Bucks
Chester
Cumberland
Dauphin
Delaware
Lancaster
Lebanon
Lehigh
Monroe
Montgomery
Northampton
Perry
Philadelphia
York	  	Maryland
Anne Arundel
Baltimore
Calvert
Carroll
Cecil
Charles
Frederick
Harford
Howard
Montgomery
North Calvert
Prince George’s
 
Washington, D.C.
District of Columbia
 
Virginia
Arlington
Fairfax
Fauquier
Loudoun
Prince William
Stafford
 
South Carolina
Bamberg
Calhoun
Dorchester
Lexington
Orangeburg	
 
(1)	In October 2011, the Partnership purchased a business with home heating oil, propane and diesel customers in these counties.	
 
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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, 2009 Residential Energy Consumption Survey (the latest survey published), these regions account for 83% (5.7 million of 6.9 million) of the households in the United States where heating oil is the main space-heating fuel and 28% (5.7 million of 20.8 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 2011, 2010, and 2009 were 1.4%, 1.2%, 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 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 price-protected customers.
Business strategy
Our business strategy is to increase operating profits and cash flow by conservatively managing our operations and growing and retaining our customer base as a retail distributor of home heating oil, propane 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 customer service training—supplemented by ongoing monitoring and guidance from management. Our Director of Quality Assurance is responsible for customer service evaluation and directs teams that conduct quality assurance assessments at operating locations. 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.
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. Our acquisition strategy has enabled us to achieve our current market position and offers us the ability 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 our 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
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.
 
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Competition
Most of our operating locations compete with numerous distributors, primarily on the basis of reliability of service, price, and response to customer needs. Each such 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 our business, we provide home heating and propane 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 a lower price than individual customers are otherwise able to obtain. Our business competes 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 on average 160 gallons per delivery and our commercial accounts receive on average 340 gallons per delivery. 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 residential home heating oil 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 protected programs, which establish either a ceiling or a fixed price per gallon 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,	 	
 	  	2011	 	 	2010	 	 	2009	 	 	2008	 	
Residential Home Heating Oil Customers	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Variable	  	 	54.9	% 	 	 	55.8	% 	 	 	52.3	% 	 	 	48.6	% 	
Ceiling	  	 	41.5	% 	 	 	41.8	% 	 	 	44.6	% 	 	 	34.4	% 	
Fixed	  	 	3.6	% 	 	 	2.4	% 	 	 	3.1	% 	 	 	17.0	% 	
 	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	  	 	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 costs of residential price-protected 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 and propane customers. Starting October 1, 2010, we have included propane customers in this calculation as several of our acquisitions since such date have included propane operations. Net customer attrition is the difference between gross customer losses and customers added through marketing efforts. Customers added through acquisitions are not included in the calculation of gross customer gains. However, additional customers that are obtained through marketing efforts at newly acquired businesses are included in these calculations. 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. (See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Customer Attrition.)
 
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Suppliers and Supply Arrangements
We purchase petroleum products for delivery in either barge, pipeline or truckload quantities, and as of September 30, 2011 have contracts with approximately 70 third-party terminals for the right to temporarily store petroleum products at their facilities. Home heating oil 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 70% of our retail home heating oil requirements for fiscal 2012. During fiscal 2011, Global Companies, NIC Holding Corp. (Northville Industries) and Sunoco Inc. provided 21.6%, 12.6% and 10.9% respectively, of our petroleum product purchases. Aside from these three suppliers, no single supplier provided more than 10% of our petroleum product supply during fiscal 2011. For fiscal 2012, we generally have supply contracts for similar quantities with Global Companies, NIC Holding Corp. (Northville Industries) and Sunoco Inc. 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 home heating 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 price-protected customers, physical inventory on hand, inventory in transit and priced purchase commitments. Currently, the Partnership’s derivative instruments are with the following counterparties: Key Bank National Association, JPMorgan Chase Bank, NA, Bank of America, N.A., Cargill, Inc., Societe Generale, Newedge USA, LLC, Bank of Montreal, Regions Bank and Wells Fargo Bank, N.A.
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. 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. 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 2011, 2010, 2009 and 2008 by quarter, is illustrated by the following chart:

 	  	Fiscal 2011	 	  	Fiscal 2010	 	  	Fiscal 2009	 	  	Fiscal 2008	 	
 	  	Low	 	  	High	 	  	Low	 	  	High	 	  	Low	 	  	High	 	  	Low	 	  	High	 	
Quarter Ended	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
December 31	  	$	2.19	  	  	$	2.54	  	  	$	1.78	  	  	$	2.12	  	  	$	1.20	  	  	$	2.85	  	  	$	2.16	  	  	$	2.71	  	
March 31	  	 	2.49	  	  	 	3.09	  	  	 	1.89	  	  	 	2.20	  	  	 	1.13	  	  	 	1.63	  	  	 	2.42	  	  	 	3.15	  	
June 30	  	 	2.75	  	  	 	3.32	  	  	 	1.87	  	  	 	2.35	  	  	 	1.31	  	  	 	1.86	  	  	 	2.88	  	  	 	3.97	  	
September 30	  	 	2.77	  	  	 	3.13	  	  	 	1.92	  	  	 	2.24	  	  	 	1.50	  	  	 	1.96	  	  	 	2.72	  	  	 	4.11	  	
Acquisitions
During fiscal 2011, the Partnership completed four acquisitions and added approximately 8,800 home heating oil and propane accounts for an aggregate cost of approximately $9.7 million, including working capital of $1.9 million. In the first two months of fiscal 2012, the Partnership purchased two businesses with a total of 12,700 home heating oil, propane and diesel accounts, for an aggregate cost of approximately $24.1 million, including working capital of $4.5 million. In fiscal 2010, we acquired five retail heating oil dealers with approximately 56,100 home heating oil, propane and security accounts for an aggregate cost of approximately $68.8 million, including $4.2 million of working capital. In fiscal 2009, we acquired one retail heating oil dealer with approximately 3,800 home heating oil accounts for an aggregate cost of approximately $4.0 million, reduced by $0.7 million of working capital credits.
 
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Employees
As of September 30, 2011, we had 2,677 employees, of whom 846 were office, clerical and customer service personnel; 797 were equipment technicians; 376 were oil truck drivers and mechanics; 391 were management and 267 were employed in sales. Of these employees 854 are represented by 34 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, we employ approximately 500 seasonal employees (353 of which are represented by the local chapters of labor unions indicated earlier) to support the requirements of the heating season. We are currently involved in 5 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 are currently not involved with any CERCLA claims, and 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 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 there is no assurance 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.
Current economic conditions could adversely affect our results of operations and financial condition.
Since 2008, there has been a down turn in economic conditions in the United States 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. More recently concerns regarding sovereign debt defaults has increased economic uncertainty.
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.
 
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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 our self 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 extreme volatility in fixed income, credit, currency and equity markets that may 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 delivery 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, N.A., 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 and propane 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, 2011, approximately 38.6% of our total home heating oil customers are 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 used weather hedging contracts for a number of years. For the fiscal 2012 heating season, we have entered into a weather hedge contract with Renaissance Trading Ltd. under which we are entitled to receive a payment of $35,000 per heating degree-day shortfall, 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, 2011 through March 31, 2012 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 and propane customer base.
Our net attrition rate of home heating oil and propane customers for fiscal 2011, 2010, and 2009 was approximately 3.5%, 5.0% and 7.6%, respectively. Starting October 1, 2010, we have included propane customers in this calculation as several of our acquisitions since such date have included propane operations. This rate represents the net of our annual gross customer losses after gross customer gains. For fiscal 2011, 2010, and 2009, we had gross customer losses of 16.7%, 16.6% and 21.1%, respectively, which were partially offset by gross customer gains during these periods of 13.2% 11.6% and 13.5%, 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:
 
 	•	 	price competition;	
 
 	•	 	customer relocations;	

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 	•	 	home sales/foreclosures;	
 
 	•	 	credit worthiness; and	
 
 	•	 	conversions to natural gas.	
The continuing unprecedented volatility in the energy markets 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 and propane 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 and propane business is subject to substantial competition. Most of our operating locations compete with numerous distributors, primarily on the basis of reliability of service, price and response to customer service needs. Each operating 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 and propane 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 2011, 2010, and 2009 were 1.4%, 1.2% and 1.6% respectively.
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.
Our 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 our sector in the future or that we will be able to acquire businesses on economically acceptable terms. Factors that may adversely affect our operating and financial results may limit our access to capital and adversely affect our ability to make acquisitions. Under the terms of our amended and restated revolving credit facility that we sometimes refer to in this Report as the revolving credit facility, 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 at least $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:
 
 	•	 	an increase in our indebtedness;	
 
 	•	 	an increase in our working capital requirements;	
 
 	•	 	our inability to integrate the operations of the acquired business;	
 
 	•	 	our inability to successfully expand our operations into new territories;	
 
 	•	 	the diversion of management’s attention from other business concerns;	
 
 	•	 	an excess of customer loss or loss of key employees from the acquired business; and	
 
 	•	 	the assumption of additional liabilities including environmental liabilities.	
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.
At September 30, 2011, the Partnership had outstanding $125.0 million (excluding discount) of senior notes maturing December 2017, which accrue interest at an annual rate of 8.875% and require semi-annual interest payments on June 1 and December 1 of each year. Our substantial indebtedness and other financial obligations could:
 
 	•	 	impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions or general partnership purposes;	
 
 	•	 	have a material adverse effect on us if we fail to comply with financial and affirmative and restrictive covenants in our debt agreements and an event of default occurs as a result of a failure that is not cured or waived;	
 
 	•	 	require us to dedicate a substantial portion of our cash flow for interest payments on our indebtedness and other financial obligations, thereby reducing the availability of our cash flow to fund working capital and capital expenditures;	
 
 	•	 	limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; and	

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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 have in the past and may in the future 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. 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. We expect that an investor will be allocated taxable income (mostly dividend income from Star Acquisitions, interest income and possibly cancellation of indebtedness income) regardless of whether a cash distribution has been paid. 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. For example, our unitholders had $16.3 million in dividend income reported on their 2010 K-1’s related to dividends received by the Partnership that the Partnership used to repurchase units.
Increases in wholesale product costs beyond current levels may have adverse effects on our business, financial condition and results of operations.
Increases in wholesale product costs beyond current levels may have adverse effects on our business, financial condition and results of operations, including the following:
 
 	•	 	higher bad debt expense and credit card processing costs as a result of higher selling prices;	
 
 	•	 	higher interest expense as a result of increased working capital borrowing to finance higher receivables and/or inventory balances;	
 
 	•	 	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; and	
 
 	•	 	higher vehicle fuel costs.	
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 $250 million, which increases to $350 million during the peak winter months from December through April of each year. The Partnership is obligated to meet certain financial covenants under the revolving credit facility, including the requirement to maintain at all times either excess availability (borrowing base less amounts borrowed and letters of credit issued) of 12.5% of the revolving credit commitment then in effect or a fixed charge coverage ratio (as defined in the revolving credit facility agreement) of not less than 1.1.
If increases in wholesale product 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 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 $7.8 million as of September 30, 2011, $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
 
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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, 2011, 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 the wholesale price of heating oil, our near term liquidity would be reduced by $40 million.
At September 30, 2011, we had approximately 141,400 customers, or 38% of our residential customer base, on the balanced payment plan. If wholesale prices increased and we failed to recalculate the balanced payments to reflect higher retail selling prices on a timely basis, our liquidity could also be reduced. 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.
Sudden and sharp oil price increases that cannot be passed on to customers may adversely affect our operating results.
Our industry is a “margin-based” business in which gross profit depends on the excess of sales prices per gallon over supply costs per gallon. Consequently, our profitability is sensitive to changes in the wholesale product cost 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 experience 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.
In 2010, the U.S. Congress 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, 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.
 
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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.
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.
As we self-insure workers’ compensation, automobile and general liability claims up to pre-established limits, 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, 2011, we had approximately $42.7 million of insurance reserves and had issued $44.2 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.
Our 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 regulations might adversely impact operations, including those relating to underground storage and transportation of the products that we sell. 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 financial condition, results of operations and ability to pay distributions to our unitholders 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 have been 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, we cannot yet estimate the compliance costs or business impact of potential national, regional or state greenhouse gas emissions reduction legislation, regulations or initiatives, since such 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.
 
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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.
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:
 
 	•	 	The general partner’s affiliates are not prohibited from engaging in other business or activities, including direct competition with us.	
 
 	•	 	The general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings and reserves, each of which can impact the amount of cash, if any, available for distribution to unitholders, and available to pay principal and interest on debt and the amount of incentive distributions payable in respect of the general partner units.	
 
 	•	 	The general partner controls the enforcement of obligations owed to us by the general partner.	
 
 	•	 	The general partner decides whether to retain separate counsel or others to perform services for us.	
 
 	•	 	In some instances the general partner may borrow funds in order to permit the payment of distributions to unitholders.	
 
 	•	 	The general partner may limit its liability and reduce its fiduciary duties, while also restricting the remedies available to unitholders for actions that might, without limitations, constitute breaches of fiduciary duty. Unitholders are deemed to have consented to some actions and conflicts of interest that might otherwise be deemed a breach of fiduciary or other duties under applicable state law.	
 
 	•	 	The general partner is allowed to take into account the interests of parties in addition to the Partnership in resolving conflicts of interest, thereby limiting its fiduciary duty to the unitholders.	
 
 	•	 	The general partner determines whether to issue additional units or other of our securities.	
 
 	•	 	The general partner determines which costs are reimbursable by us.	
 
 	•	 	The general partner is not restricted from causing us to pay the general partner or its affiliates for any services rendered on terms that are fair and reasonable to us or entering into additional contractual arrangements with any of these entities on our behalf.	
The risk of global terrorism and political unrest may adversely affect the economy and the price and availability of the products that we sell 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 the products that we sell, our results of operations, our ability to raise capital and our future growth. The impact that the foregoing may have on our 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, markets and facilities, and the source of the products that we sell could be direct or indirect targets. Terrorist activity may also hinder our ability to transport our products 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 the prices of our products. 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.
 
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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:
 
 	•	 	profitability of operations;	
 
 	•	 	required principal and interest payments on debt or debt prepayments;	
 
 	•	 	debt covenants;	
 
 	•	 	margin account requirements;	
 
 	•	 	cost of acquisitions;	
 
 	•	 	issuance of debt and equity securities;	
 
 	•	 	fluctuations in working capital;	
 
 	•	 	capital expenditures;	
 
 	•	 	adjustments in reserves;	
 
 	•	 	prevailing economic conditions;	
 
 	•	 	financial, business and other factors;	
 
 	•	 	increased pension funding requirements;	
 
 	•	 	the amount of our net operating loss carry forwards (as subject to any Section 382 limitation and utilization); and	
 
 	•	 	the amount of cash taxes we have to pay in Federal, State and local corporate income and franchise taxes.	
Our operations are conducted through Petro Holdings, Inc. (a Minnesota corporation that is our indirect wholly owned subsidiary) and its subsidiaries, all of which are corporations subject to Federal and state income taxes. At December 31, 2011, we estimate that our Federal (Net Operating Loss carryforwards (“NOLs”) will be $12.8 million subject to annual limitations of between $1.0 million and $2.2 million that can be used. As we have almost fully exhausted our Federal NOLs, the amount of cash taxes that our subsidiaries will pay going forward will increase significantly in future years, which will reduce the annual amount of cash available for distribution to unitholders.
Most of these factors are beyond the control of the general partner. Our 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 Partnership’s amended and restated revolving credit facility and the indenture for its senior notes due December 2017, both impose certain restrictions on its ability to pay distributions to unitholders. The most restrictive covenant is found in the revolving credit facility. In order to make any distributions to unitholders, the Partnership must maintain availability of 17.5% of the maximum facility size and a fixed charge coverage ratio of not less than 1.15, which is based on Adjusted EBITDA. (See Note 10 of the Notes to the Consolidated Financial Statements—Long-Term Debt and Bank Facility Borrowings)
We are a holding company and have no material operations or assets. Accordingly, we are dependent on distributions from our subsidiaries to service our debt obligations. These distributions are not guaranteed and may be restricted. In addition, the notes are non-recourse to our subsidiaries.
We are a holding company for our direct and indirect subsidiaries. We have no material operations and only limited assets. Accordingly, we are dependent on cash distributions from our subsidiaries to service our debt obligations. Noteholders will not receive payments required by the notes unless our subsidiaries are able to make distributions to us after they first comply with the restrictions on distributions under the terms of their own borrowing arrangements and reserve any necessary amounts to meet their own financial obligations.
Additionally, our obligations under the notes are non-recourse to our subsidiaries. Therefore, if we should fail to pay interest or principal on the notes or breach any of our other obligations under the notes or the indenture, noteholders would not be able to obtain any such payments or obtain any other remedy from our subsidiaries, which are not liable for any of our obligations under the indenture or the notes.
 
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We are not required to accumulate cash for the purpose of meeting our future obligations to our noteholders, which may limit the cash available to service our notes.
Subject to the limitations on restricted payments that are contained in the revolving credit facility and in the indenture governing the notes, we are not required to accumulate cash for the purpose of meeting our future obligations to our noteholders. As a result, we do not expect to accumulate significant amounts of cash. Our general partner will determine the future use of our cash resources and has broad discretion in determining such uses and in establishing reserves for such uses, which may include but are not limited to:
 
 	•	 	complying with the terms of any of our agreements or obligations;	
 
 	•	 	providing for distributions of cash to our unitholders in accordance with the requirements of our Partnership Agreement;	
 
 	•	 	providing for future capital expenditures and other payments deemed by our general partner to be necessary or advisable, including to make acquisitions; and	
 
 	•	 	repurchasing common units.	
Depending on the timing and amount our use of cash, this could significantly reduce the cash available to us in subsequent periods to make payments on the notes.
Restrictive covenants in the agreements governing our indebtedness and other financial obligations of our subsidiaries may reduce our operating flexibility.
The indenture governing our notes and the revolving credit facility agreement contain various covenants that limit our ability and the ability of specified subsidiaries of ours to, among other things:
 
 	•	 	incur additional indebtedness;	
 
 	•	 	make distributions to our unitholders;	
 
 	•	 	purchase or redeem our outstanding equity interests or subordinated debt;	
 
 	•	 	make specified investments;	
 
 	•	 	create liens;	
 
 	•	 	sell assets;	
 
 	•	 	engage in specified transactions with affiliates;	
 
 	•	 	restrict the ability of our subsidiaries to make specified payments, loans, guarantees and transfers of assets or interests in assets;	
 
 	•	 	engage in sale-leaseback transactions;	
 
 	•	 	effect a merger or consolidation with or into other companies or a sale of all or substantially all of our properties or assets; and	
 
 	•	 	engage in other lines of business.	
These restrictions could limit our ability to obtain future financings, make needed capital expenditures, withstand a future downturn in our business or the economy in general, conduct operations or otherwise take advantage of business opportunities that may arise. The agreements also require us to maintain specified financial ratios and satisfy other financial conditions. Our ability to meet those financial ratios and conditions can be affected by events beyond their control, such as weather conditions and general economic conditions. Accordingly, we may be unable to meet those ratios and conditions.
Any breach of any of these covenants or failure to meet any of these ratios or conditions could result in a default under the terms of the relevant indebtedness or other financial obligations, which could cause such indebtedness or other financial obligations, and by reason of cross-default provisions, the notes, to become immediately due and payable. If we were unable to repay those amounts, the lenders could initiate a bankruptcy proceeding or liquidation proceeding or proceed against the collateral, if any. If the lenders of our indebtedness or other financial obligations accelerate the repayment of borrowings or other amounts owed, we may not have sufficient assets to repay our indebtedness or other financial obligations, including the notes.
 
ITEM 1B.	UNRESOLVED STAFF COMMENTS	
Not applicable.
 
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ITEM 2.	PROPERTIES	
We provide services to our customers from Maine to South Carolina of the United States from 36 principal operating locations and 53 depots, 31 of which are owned and 58 of which are leased. As of September 30, 2011, we had a fleet of 984 truck and transport vehicles, the majority of which were owned and 1,082 service vans, the majority of which were leased. We lease our corporate headquarters in Stamford, Connecticut. Our obligations under our revolving 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 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 2011 and 2010 quarters indicated.

 	  	SGU – Common Unit Price Range	 	  	Distributions Declared	 	
 	  	High	 	  	Low	 	  	per Unit	 	
 	  	Fiscal
Year
2011	 	  	Fiscal
Year
2010	 	  	Fiscal
Year
2011	 	  	Fiscal
Year
2010	 	  	Fiscal
Year
2011	 	  	Fiscal
Year
2010	 	
Quarter Ended	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
December 31,	  	$	5.65	  	  	$	4.17	  	  	$	4.74	  	  	$	3.55	  	  	$	0.0725	  	  	$	0.0675	  	
March 31,	  	$	5.84	  	  	$	4.51	  	  	$	5.17	  	  	$	3.98	  	  	$	0.0775	  	  	$	0.0725	  	
June 30,	  	$	5.96	  	  	$	4.46	  	  	$	5.33	  	  	$	4.25	  	  	$	0.0775	  	  	$	0.0725	  	
September 30,	  	$	5.39	  	  	$	4.74	  	  	$	4.66	  	  	$	4.32	  	  	$	0.0775	  	  	$	0.0725	  	
As of November 30, 2011, there were approximately 410 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
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 the payment of debt principal and interest, for minimum quarterly distributions during the next four quarters and to comply with applicable laws and the terms of any debt agreements or other agreement 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.
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 4. 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 revolving credit facility, the Partnership must maintain availability of 17.5% of the maximum facility size and a fixed charge coverage ratio of not less than 1.15 in order to pay any distribution.
 
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On October 25, 2011, we declared a quarterly distribution of $0.0775 per unit, or $0.31 per unit on an annualized basis, on all common units in respect of the fourth quarter of fiscal 2011 payable on November 14, 2011 to holders of record on November 4, 2011. In accordance with our Partnership Agreement, the amount of distributions in excess of the minimum quarterly distribution of $0.0675, are distributed (i) 90% to the holders of common units and (ii) 10% to the holders of the general partner units (until certain distribution levels are met), subject to the management incentive compensation plan. As a result, $5.0 million was paid to the common unit holders, $0.06 million was paid to the general partner and $0.04 million was paid to management pursuant to the management incentive compensation plan.
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. The authorized common unit repurchases may be made from time-to-time in the open market, in privately negotiated transactions or in such other manner deemed appropriate by management. In order to facilitate the repurchase program, the Partnership entered into a prearranged unit repurchase plan under Rule 10b5-1 of the Securities Act of 1933, as amended for up to 4.0 million common units with a third party broker. There is no guarantee of the exact number of units that will be purchased under the program and the Partnership may discontinue purchases at any time. The program does not have a time limit. The Partnership’s repurchase activities take into account SEC safe harbor rules and guidance for issuer repurchases. All of the common units purchased in the repurchase program will be retired.
(in thousands, except per unit amounts)

Period	  	Total Number of  Units
Purchased as Part of a
Publicly Announced Plan or
Program	 	 	Average Price
Paid per  Unit (b)	 	  	Maximum Number of  Units
that May Yet Be Purchased
Under the Program	 	
Number of units authorized	  	 	 	 	 	 	 	 	  	 	7,000	  	
Fiscal year 2010 total (a)	  	 	1,197	  	 	$	4.44	  	  	 	5,803	  	
 	  	 	 	 	 	 	 	 	  	 	 	 	
Fiscal year 2011 first quarter	  	 	—  	  	 	$	—  	  	  	 	5,803	  	
 	  	 	 	 	 	 	 	 	  	 	 	 	
Fiscal year 2011 second quarter	  	 	—  	  	 	$	—  	  	  	 	5,803	  	
 	  	 	 	 	 	 	 	 	  	 	 	 	
Fiscal year 2011 third quarter	  	 	—  	  	 	$	—  	  	  	 	5,803	  	
 	  	 	 	 	 	 	 	 	  	 	 	 	
July 2011	  	 	—  	  	 	$	—  	  	  	 	5,803	  	
August 2011	  	 	1,835	(c) 	 	$	5.22	  	  	 	3,968	  	
September 2011	  	 	273	  	 	$	5.03	  	  	 	3,695	  	
 	  	 	 	 	 	 	 	 	  	 	 	 	
Fiscal year 2011 fourth quarter total	  	 	2,108	  	 	$	5.19	  	  	 	3,695	  	
 	  	 	 	 	 	 	 	 	  	 	 	 	
Fiscal year 2011 total	  	 	2,108	  	 	$	5.19	  	  	 	3,695	  	
 	  	 	 	 	 	 	 	 	  	 	 	 	
October 2011	  	 	226	  	 	$	4.96	  	  	 	3,469	  	
November 2011	  	 	215	  	 	$	4.95	  	  	 	3,254	  	
 
(a)	In fiscal year 2010 we also repurchased 6.9 million common units, concluding a repurchase plan authorized by the Board of Directors on July 21, 2009.	
(b)	Amounts include repurchase costs.	
(c)	August 2011 common unit repurchase include 1.5 million common units acquired in a private sale.	
 
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ITEM 6.	SELECTED HISTORICAL FINANCIAL AND OPERATING DATA	
The selected financial data as of September 30, 2011 and 2010, and for the years ended September 30, 2011, 2010 and 2009 is derived from the financial statements of the Partnership included elsewhere in this Report. The selected financial data as of September 30, 2009, 2008 and 2007 and for the years ended September 30, 2008 and 2007 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)	  	2011	 	  	2010	 	 	2009	 	 	2008	 	 	2007	 	
Statement of Operations Data:	  	 	 	 	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Sales	  	$	1,591,310	  	  	$	1,212,776	  	 	$	1,206,813	  	 	$	1,543,093	  	 	$	1,267,175	  	
Costs and expenses:	  	 	 	 	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cost of sales	  	 	1,237,341	  	  	 	904,047	  	 	 	875,755	  	 	 	1,257,592	  	 	 	981,559	  	
(Increase) decrease in the fair value of derivative instruments	  	 	2,567	  	  	 	(5,622	) 	 	 	(13,690	) 	 	 	25,467	  	 	 	(15,664	) 	
Delivery and branch expenses	  	 	250,762	  	  	 	218,625	  	 	 	224,478	  	 	 	213,902	  	 	 	199,509	  	
Depreciation and amortization expenses	  	 	17,884	  	  	 	15,745	  	 	 	19,406	  	 	 	26,784	  	 	 	28,995	  	
General and administrative expenses	  	 	20,709	  	  	 	21,397	  	 	 	20,742	  	 	 	16,043	  	 	 	17,665	  	
 	  	 	 	 	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating income	  	 	62,047	  	  	 	58,584	  	 	 	80,122	  	 	 	3,305	  	 	 	55,111	  	
Interest expense, net	  	 	10,840	  	  	 	10,820	  	 	 	13,637	  	 	 	13,808	  	 	 	11,525	  	
Amortization of debt issuance costs	  	 	2,440	  	  	 	2,680	  	 	 	2,750	  	 	 	2,339	  	 	 	2,282	  	
(Gain) loss on redemption of debt	  	 	1,700	  	  	 	1,132	  	 	 	(9,706	) 	 	 	—  	  	 	 	—  	  	
 	  	 	 	 	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income (loss) from continuing operations before income taxes	  	 	47,067	  	  	 	43,952	  	 	 	73,441	  	 	 	(12,842	) 	 	 	41,304	  	
Income tax expense (benefit)	  	 	22,723	  	  	 	15,632	  	 	 	(57,597	) 	 	 	566	  	 	 	2,002	  	
 	  	 	 	 	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income (loss) from continuing operations	  	 	24,344	  	  	 	28,320	  	 	 	131,038	  	 	 	(13,408	) 	 	 	39,302	  	
Loss on sales of discontinued operations, net of income taxes	  	 	—  	  	  	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	(1,061	) 	
 	  	 	 	 	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net income (loss)	  	$	24,344	  	  	$	28,320	  	 	$	131,038	  	 	$	(13,408	) 	 	$	38,241	  	
 	  	 	 	 	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Weighted average number of limited partner units:	  	 	 	 	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Basic and diluted	  	 	66,822	  	  	 	70,019	  	 	 	75,738	  	 	 	75,774	  	 	 	75,774	  	

 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	  	Fiscal Years Ended September 30,	 	
(in thousands, except per unit data)	  	2011	 	 	2010	 	 	2009	 	 	2008	 	 	2007	 	
Per Unit Data:	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Basic and diluted income (loss) from continuing operations per unit (a)	  	$	0.35	  	 	$	0.38	  	 	$	1.43	  	 	$	(0.18	) 	 	$	0.51	  	
Basic and diluted net income (loss) per unit (a)	  	$	0.35	  	 	$	0.38	  	 	$	1.43	  	 	$	(0.18	) 	 	$	0.50	  	
Cash distribution declared per common unit	  	$	0.305	  	 	$	0.2850	  	 	$	0.2025	  	 	$	—  	  	 	$	—  	  	
Balance Sheet Data (end of period):	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Current assets	  	$	299,417	  	 	$	246,863	  	 	$	376,898	  	 	$	344,299	  	 	$	320,503	  	
Total assets	  	$	626,129	  	 	$	582,508	  	 	$	664,126	  	 	$	605,433	  	 	$	602,104	  	
Long-term debt	  	$	124,263	  	 	$	82,770	  	 	$	133,112	  	 	$	173,752	  	 	$	173,941	  	
Partners’ Capital	  	$	272,633	  	 	$	279,911	  	 	$	306,334	  	 	$	199,977	  	 	$	216,331	  	
Summary Cash Flow Data:	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net cash provided by operating activities	  	$	39,402	  	 	$	44,429	  	 	$	78,455	  	 	$	71,555	  	 	$	51,115	  	
Net cash used in investing activities	  	$	(15,928	) 	 	$	(73,956	) 	 	$	(7,568	) 	 	$	(5,488	) 	 	$	(29,254	) 	
Net cash provided by (used in) financing activities	  	$	2,253	  	 	$	(104,571	) 	 	$	(54,535	) 	 	$	(145	) 	 	$	(96	) 	
Other Data:	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Earnings from continuing operations before net interest expense, income taxes, depreciation and amortization (EBITDA) (b)	  	$	78,231	  	 	$	73,197	  	 	$	109,234	  	 	$	30,089	  	 	$	84,106	  	
Adjusted EBITDA (b)	  	$	82,498	  	 	$	68,707	  	 	$	85,838	  	 	$	55,556	  	 	$	68,442	  	
Retail home heating oil and propane gallons sold	  	 	355,569	  	 	 	310,323	  	 	 	351,630	  	 	 	353,200	  	 	 	378,707	  	
 
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(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)	  	2011	 	 	2010	 	 	2009	 	 	2008	 	 	2007	 	
Net income (loss) from continuing operations	  	$	24,344	  	 	$	28,320	  	 	$	131,038	  	 	$	(13,408	) 	 	$	39,302	  	
Plus:	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income tax expense (benefit)	  	 	22,723	  	 	 	15,632	  	 	 	(57,597	) 	 	 	566	  	 	 	2,002	  	
Amortization of debt issuance cost	  	 	2,440	  	 	 	2,680	  	 	 	2,750	  	 	 	2,339	  	 	 	2,282	  	
Interest expense, net	  	 	10,840	  	 	 	10,820	  	 	 	13,637	  	 	 	13,808	  	 	 	11,525	  	
Depreciation and amortization	  	 	17,884	  	 	 	15,745	  	 	 	19,406	  	 	 	26,784	  	 	 	28,995	  	
 	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
EBITDA from continuing operations	  	 	78,231	  	 	 	73,197	  	 	 	109,234	  	 	 	30,089	  	 	 	84,106	  	
(Increase)/decrease in the fair value of derivative instruments	  	 	2,567	  	 	 	(5,622	) 	 	 	(13,690	) 	 	 	25,467	  	 	 	(15,664	) 	
(Gain) loss on redemption of debt	  	 	1,700	  	 	 	1,132	  	 	 	(9,706	) 	 	 	—  	  	 	 	—  	  	
 	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Adjusted EBITDA	  	 	82,498	  	 	 	68,707	  	 	 	85,838	  	 	 	55,556	  	 	 	68,442	  	
 	 	 	 	 	 	
Add/(subtract)	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income tax (expense) benefit	  	 	(22,723	) 	 	 	(15,632	) 	 	 	57,597	  	 	 	(566	) 	 	 	(2,002	) 	
Interest expense, net	  	 	(10,840	) 	 	 	(10,820	) 	 	 	(13,637	) 	 	 	(13,808	) 	 	 	(11,525	) 	
Provision for losses on accounts receivable	  	 	10,388	  	 	 	5,279	  	 	 	10,310	  	 	 	11,961	  	 	 	5,726	  	
(Increase) decrease in accounts receivables	  	 	(31,593	) 	 	 	(4,570	) 	 	 	26,657	  	 	 	(28,002	) 	 	 	5,761	  	
(Increase) decrease in inventories	  	 	(13,189	) 	 	 	(2,012	) 	 	 	(17,747	) 	 	 	41,368	  	 	 	(8,222	) 	
Increase (decrease) in customer credit balances	  	 	(1,776	) 	 	 	(9,250	) 	 	 	(11,964	) 	 	 	13,390	  	 	 	(3,724	) 	
Change in deferred taxes	  	 	15,831	  	 	 	13,331	  	 	 	(61,355	) 	 	 	—  	  	 	 	—  	  	
Change in other operating assets and liabilities	  	 	10,806	  	 	 	(604	) 	 	 	2,756	  	 	 	(8,344	) 	 	 	(3,341	) 	
 	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net cash provided by operating activities	  	$	39,402	  	 	$	44,429	  	 	$	78,455	  	 	$	71,555	  	 	$	51,115	  	
 	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net cash used in investing activities	  	$	(15,928	) 	 	$	(73,956	) 	 	$	(7,568	) 	 	$	(5,488	) 	 	$	(29,254	) 	
 	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net cash provided by (used in) financing activities	  	$	2,253	  	 	$	(104,571	) 	 	$	(54,535	) 	 	$	(145	) 	 	$	(96	) 	

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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 the products that we sell, the consumption patterns of our customers, our ability to obtain satisfactory gross profit margins, our ability to obtain new customers and retain existing customers, our ability to make strategic acquisitions, the impact of litigation, our ability to contract for our current and future supply needs, natural gas conversions, future union relations and the outcome of current and future union negotiations, the impact of current and future governmental regulations, including environmental, health, and safety regulations, the ability to attract and retain employees, customer credit worthiness, counterparty credit worthiness, marketing plans, general economic conditions and new technology. All statements other than statements of historical facts included in this Report including, without limitation, the statements under “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and elsewhere herein, are forward-looking statements. Without limiting the foregoing, the words “believe,” “anticipate,” “plan,” “expect,” “seek,” “estimate,” and similar expressions are intended to identify forward-looking statements. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to be correct and actual results may differ materially from those projected as a result of certain risks and uncertainties. These risks and uncertainties include, but are not limited to, those set forth under the heading “Risk Factors” and “Business Strategy.” 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 Report.
Seasonality
The following matters should be considered in analyzing our financial results. Our fiscal year ends on September 30. All references to quarters and years respectively in this document are to fiscal quarters and years unless otherwise noted. The seasonal nature of our business has resulted, on average during the last five years, in the sale of approximately 30% of our volume of home heating oil and propane in the first fiscal quarter and 50% of our volume in the second fiscal quarter of each fiscal year, the peak heating season. We generally realize net income in both of these quarters and net losses during the quarters ending June and September. In addition, sales volume typically fluctuates from year to year in response to variations in weather, wholesale energy prices and other factors.
Degree Day
A “degree day” is an industry measurement of temperature designed to evaluate energy demand and consumption. Degree days are based on how far the average temperature departs from 65°F. Each degree of temperature above 65°F is counted as one cooling degree day, and each degree of temperature below 65°F is counted as one heating degree day. Degree days are accumulated each day over the course of a year and can be compared to a monthly or a long-term (multi-year) average to see if a month or a year was warmer or cooler than usual. Degree days are officially observed by the National Weather Service and officially archived by the National Climatic Data Center. For purposes of evaluating our results of operations, we use the normal heating degree day amount as reported by the National Weather Service in our operating areas.
Impact on Operating Results of Increasing Wholesale Product Costs
During the fiscal 2011 heating season, wholesale product costs increased significantly, which limited our ability to maintain and/or expand margins for variable and ceiling priced customers. Conversely, during certain peak months of the fiscal 2010 and 2009 heating seasons, wholesale product costs declined, which contributed to our ability to expand our per gallon margins during these periods, as wholesale prices decreased more rapidly than our retail prices. For example, over 90% of our ceiling customers reached their maximum contract price during the three months ended March 31, 2011, as compared to 70% during the three months ended March 31, 2010. During the three months ended March 31, 2009, less than 1% of our ceiling customers reached their maximum contract price. If wholesale product costs continue to increase, the Partnership’s ability to maintain and/or expand per gallon margins could be greatly diminished, our profitability measures would be adversely impacted, gross customer losses could increase and our ability to attract new customers might decrease. The 2011 increase in the cost of home heating oil and other petroleum products in general has also resulted in an increase in certain operating expenses that are directly tied to the underlying cost of product such as bad debt expense, credit card processing costs, vehicle fuels and other transportation expenses. For fiscal 2011, the Partnership increased its reserve rate for doubtful accounts when compared to fiscal 2010 in response to an 11 day increase in the days sales outstanding for accounts receivable, increased volume due to colder temperatures and higher selling prices. If wholesale product
 
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costs continue to increase, future operating costs will also increase. In addition, interest expense may rise further as the Partnership is required to finance a higher level of accounts receivable and inventory.
Home Heating Oil Price Volatility
In recent years, the wholesale price of home heating oil has been extremely volatile, resulting in increased consumer price sensitivity to heating costs and increased gross customer attrition. As a commodity, the price of home heating oil is generally impacted by many factors, including economic and geopolitical forces. The price of home heating oil is closely linked to the price refiners pay for crude oil, which is the principal cost component of home heating oil. The volatility in the wholesale cost of home heating oil, as measured by the New York Mercantile Exchange (“Nymex”) price per gallon for fiscal 2011, 2010, 2009, and 2008 by quarter, is illustrated in the following chart:

 	  	Fiscal 2011	 	  	Fiscal 2010	 	  	Fiscal 2009	 	  	Fiscal 2008	 	
Quarter Ended	  	Low	 	  	High	 	  	Low	 	  	High	 	  	Low	 	  	High	 	  	Low	 	  	High	 	
December 31	  	$	2.19	  	  	$	2.54	  	  	$	1.78	  	  	$	2.12	  	  	$	1.20	  	  	$	2.85	  	  	$	2.16	  	  	$	2.71	  	
March 31	  	 	2.49	  	  	 	3.09	  	  	 	1.89	  	  	 	2.20	  	  	 	1.13	  	  	 	1.63	  	  	 	2.42	  	  	 	3.15	  	
June 30	  	 	2.75	  	  	 	3.32	  	  	 	1.87	  	  	 	2.35	  	  	 	1.31	  	  	 	1.86	  	  	 	2.88	  	  	 	3.97	  	
September 30	  	 	2.77	  	  	 	3.13	  	  	 	1.92	  	  	 	2.24	  	  	 	1.50	  	  	 	1.96	  	  	 	2.72	  	  	 	4.11	  	
Impact on Liquidity of Wholesale Product Cost Volatility
Our liquidity is adversely impacted in times of increasing wholesale product costs, as we must use cash to fund our hedging requirements and a portion of the increased levels of accounts receivable and inventory. Our liquidity is also adversely impacted at times by sudden and sharp decreases in wholesale product costs due to the increased margin requirements for futures contracts and collateral requirements for options and swaps that we use to manage market risks related to our ceiling and fixed price customers and physical inventory that are not immediately offset by lower inventory and accounts receivable carrying costs.
Impact of Warm Weather on Operating Results; Weather Hedge Contract
Weather conditions have a significant impact on the demand for home heating oil and propane because our customers depend on these products principally for heating purposes. Actual weather conditions can vary substantially from year to year, significantly affecting our financial performance. To partially mitigate the adverse effect of warm weather on our cash flows, we have used weather hedging contracts for a number of years. For the fiscal 2012 heating season, we have entered into a weather hedge contract with Renaissance Trading Ltd. under which we are entitled to receive a payment of $35,000 per heating degree-day shortfall, 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, 2011 through March 31, 2012 taken as a whole, and has a maximum payout of $12.5 million. In six of the last 30 years, we would have received a payment under this contract. The average payment for those six years would have been $5.4 million.
Per Gallon Gross Profit Margins
We believe the change in home heating oil and propane margins should be evaluated on a cents per gallon basis, before the effects of increases or decreases in the fair value of derivative instruments, as we believe that realized per gallon margins should not include the impact of non-cash changes in the market value of hedges before the settlement of the underlying transaction.
A significant portion of our home heating oil 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 (generally 12 months). When these price-protected customers agree to purchase home heating oil from us for the next heating season, we purchase option contracts, swaps and futures contracts for a substantial majority of the heating oil that we expect to sell to these customers. The amount of home heating oil volume that we hedge per price-protected customer is based upon the estimated fuel consumption per average customer, per month. In the event that the actual usage exceeds the amount of the hedged volume on a monthly basis, we may be required to obtain additional volume at unfavorable costs. In addition, should actual usage in any month be less than the hedged volume, our hedging losses could be greater, reducing expected margins.
 
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Derivatives
FASB ASC 815-10-05 Derivatives and Hedging topic, established accounting and reporting standards requiring that derivative instruments be recorded at fair value and included in the consolidated balance sheet as assets or liabilities. To the extent derivative instruments designated as cash flow hedges are effective, as defined under this standard, changes in fair value are recognized in other comprehensive income until the forecasted hedged item is recognized in earnings. We have elected not to designate our derivative instruments as hedging instruments under this standard, and, as a result, the changes in fair value of the derivative instruments are recognized in our statement of operations. Therefore, we experience volatility in earnings as outstanding derivative instruments are marked to market and non-cash gains and losses are recorded prior to the sale of the commodity to the customer. The volatility in any given period related to unrealized non-cash gains or losses on derivative home heating oil and propane instruments can be significant to our overall results. However, we ultimately expect those gains and losses to be offset by the cost of product when purchased.
Income Taxes—Net Operating Loss Carry Forward
At December 31, 2011, we estimate that our Federal (Net Operating Loss carryforwards (“NOLs”) will be $12.8 million subject to annual limitations of between $1.0 million and $2.2 million that can be used. As we have almost fully exhausted our Federal NOLs, the amount of cash taxes that our subsidiaries will pay going forward will increase significantly in future years, which will reduce the annual amount of cash available for distribution to unitholders.
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 are required to pay. The amount of depreciation and amortization that we deduct for book (i.e. financial reporting) purposes will differ from the amount that our subsidiaries can deduct for tax purposes. The table below compares the estimated depreciation and amortization for book purposes to the amount that our subsidiaries expect to deduct for tax purposes. Our subsidiaries file their tax returns based on a calendar year. The amounts below are based on our September 30, fiscal year.
Estimated Depreciation and Amortization Expense

(in thousands)
Fiscal Year	  	Book	 	  	Tax	 	
2012	  	$	14,758	  	  	$	29,823	  	
2013	  	 	13,448	  	  	 	27,145	  	
2014	  	 	12,102	  	  	 	22,978	  	
2015	  	 	10,824	  	  	 	19,870	  	
2016	  	 	9,348	  	  	 	14,725	  	
In addition, the Partnership incurs approximately $2 million a year in general and administrative expenses that are not subject to Federal or state income taxes and do not provide the Partnership any income tax deductions.
Income Taxes—Consideration of 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, 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 have considered the possibility of 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. After reviewing the potential costs and benefits of such a conversion, we have decided not to proceed with it at this time, but we may consider it further in the future.
 
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EBITDA and Adjusted EBITDA (non-GAAP financial measures)
EBITDA (Earnings from continuing operations before net interest expense, income taxes, depreciation and amortization) and Adjusted EBITDA (Earnings from continuing operations before net interest expense, income taxes, depreciation and amortization, (increase) decrease in the fair value of derivatives, gain or loss on debt redemption, goodwill impairment, and other non-cash and non-operating charges) are non-GAAP financial measures that are used as supplemental financial measures by management and external users of our financial statements, such as investors, commercial banks and research analysts, to assess:
 
 	•	 	our compliance with certain financial covenants included in our debt agreements;	
 
 	•	 	our financial performance without regard to financing methods, capital structure, income taxes or historical cost basis;	
 
 	•	 	our ability to generate cash sufficient to pay interest on our indebtedness and to make distributions to our partners;	
 
 	•	 	our operating performance and return on invested capital compared to those of other companies in the retail distribution of refined petroleum products business, without regard to financing methods and capital structure; and	
 
 	•	 	the viability of acquisitions and capital expenditure projects and the overall rates of return of alternative investment opportunities.	
The method of calculating Adjusted EBITDA may not be consistent with that of other companies and each of EBITDA and Adjusted EBITDA has its limitations as an analytical tool, should not be considered in isolation and should be viewed in conjunction with measurements that are computed in accordance with GAAP. Some of the limitations of EBITDA and Adjusted EBITDA are:
 
 	•	 	EBITDA and Adjusted EBITDA do not reflect our cash used for capital expenditures;	
 
 	•	 	Although depreciation and amortization are non-cash charges, the assets being depreciated or amortized often will have to be replaced and EBITDA and Adjusted EBITDA do not reflect the cash requirements for such replacements;	
 
 	•	 	EBITDA and Adjusted EBITDA do not reflect changes in, or cash requirements for, our working capital requirements;	
 
 	•	 	EBITDA and Adjusted EBITDA do not reflect the cash necessary to make payments of interest or principal on our indebtedness; and	
 
 	•	 	EBITDA and Adjusted EBITDA do not reflect the cash required to pay taxes.	
Acquisitions
During fiscal 2011, the Partnership completed four acquisitions and added approximately 8,800 home heating oil and propane accounts. (In addition, in the first two months of fiscal 2012, the Partnership purchased two businesses with a total of 12,700 home heating oil, propane and diesel accounts). During fiscal 2010, the Partnership completed five acquisitions and added approximately 56,100 home heating oil, propane and security accounts. In analyzing the Partnership’s results, the timing of acquisitions can have an impact on the comparability of our results. For example, while the 2010 acquisitions provided additional revenue in fiscal 2010, the Partnership’s profitability measures, such as operating income and net income were adversely impacted by such acquisitions as the associated product costs and operating expenses of the 2010 acquisitions exceeded revenues, reflecting the fact that such acquisitions were all completed after the end of the fiscal 2010 heating season.
Customer Attrition
We measure net customer attrition on an ongoing basis for our full service residential and commercial home heating oil and propane customers. Since October 1, 2010, we have included propane customers in this calculation as several of our acquisitions since that date have included propane operations. Net customer attrition is the difference between gross customer losses and customers added through marketing efforts. Customers added through acquisitions are not included in the calculation of gross customer gains. However, additional customers that are obtained through marketing efforts at newly acquired businesses are included in these calculations. 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.
 
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Gross customer gains and gross customer losses

 	  	Fiscal Year Ended	 	
 	  	2011	 	 	2010 (a)	 	 	2009 (a)	 	
 	  	Gross Customer	 	  	Net	 	 	Gross Customer	 	  	Net	 	 	Gross Customer	 	  	Net	 	
 	  	Gains	 	  	Losses	 	  	Attrition	 	 	Gains	 	  	Losses	 	  	Attrition	 	 	Gains	 	  	Losses	 	  	Attrition	 	
First Quarter	  	 	21,900	  	  	 	24,100	  	  	 	(2,200	) 	 	 	19,000	  	  	 	21,600	  	  	 	(2,600	) 	 	 	26,300	  	  	 	31,800	  	  	 	(5,500	) 	
Second Quarter	  	 	11,800	  	  	 	17,200	  	  	 	(5,400	) 	 	 	11,000	  	  	 	14,200	  	  	 	(3,200	) 	 	 	11,700	  	  	 	24,100	  	  	 	(12,400	) 	
Third Quarter	  	 	6,000	  	  	 	11,400	  	  	 	(5,400	) 	 	 	5,300	  	  	 	12,600	  	  	 	(7,300	) 	 	 	5,900	  	  	 	12,300	  	  	 	(6,400	) 	
Fourth Quarter	  	 	15,300	  	  	 	17,100	  	  	 	(1,800	) 	 	 	10,100	  	  	 	16,800	  	  	 	(6,700	) 	 	 	10,500	  	  	 	16,500	  	  	 	(6,000	) 	
 	  	 	 	 	  	 	 	 	  	 	 	 	 	 	 	 	  	 	 	 	  	 	 	 	 	 	 	 	  	 	 	 	  	 	 	 	
Total	  	 	55,000	  	  	 	69,800	  	  	 	(14,800	) 	 	 	45,400	  	  	 	65,200	  	  	 	(19,800	) 	 	 	54,400	  	  	 	84,700	  	  	 	(30,300	) 	
 	  	 	 	 	  	 	 	 	  	 	 	 	 	 	 	 	  	 	 	 	  	 	 	 	 	 	 	 	  	 	 	 	  	 	 	 	
Net customer attrition as a percentage of the home heating oil customer base.

 	  	Fiscal Year Ended	 	
 	  	2011	 	 	2010 (a)	 	 	2009 (a)	 	
 	  	Gross Customer	 	 	Net	 	 	Gross Customer	 	 	Net	 	 	Gross Customer	 	 	Net	 	
 	  	Gains	 	 	Losses	 	 	Attrition	 	 	Gains	 	 	Losses	 	 	Attrition	 	 	Gains	 	 	Losses	 	 	Attrition	 	
First Quarter	  	 	5.3	% 	 	 	5.8	% 	 	 	(0.5	%) 	 	 	4.8	% 	 	 	5.5	% 	 	 	(0.7	%) 	 	 	6.5	% 	 	 	7.9	% 	 	 	(1.4	%) 	
Second Quarter	  	 	2.8	% 	 	 	4.1	% 	 	 	(1.3	%) 	 	 	2.8	% 	 	 	3.6	% 	 	 	(0.8	%) 	 	 	2.9	% 	 	 	6.0	% 	 	 	(3.1	%) 	
Third Quarter	  	 	1.5	% 	 	 	2.8	% 	 	 	(1.3	%) 	 	 	1.4	% 	 	 	3.2	% 	 	 	(1.8	%) 	 	 	1.5	% 	 	 	3.1	% 	 	 	(1.6	%) 	
Fourth Quarter	  	 	3.6	% 	 	 	4.0	% 	 	 	(0.4	%) 	 	 	2.6	% 	 	 	4.3	% 	 	 	(1.7	%) 	 	 	2.6	% 	 	 	4.1	% 	 	 	(1.5	%) 	
 	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	  	 	13.2	% 	 	 	16.7	% 	 	 	(3.5	%) 	 	 	11.6	% 	 	 	16.6	% 	 	 	(5.0	%) 	 	 	13.5	% 	 	 	21.1	% 	 	 	(7.6	%) 	

(a)	Prior to October 1, 2010, we measured only home heating oil net customer attrition.	
During fiscal 2011, we lost 14,800 accounts (net), or 3.5% of our home heating oil and propane customer base, as compared to a loss of 19,800 accounts (net), or 5.0% of our customer base, during fiscal 2010. The improvement in our net attrition rate of 1.5% (or 5,000 accounts, net) was due to growth in our propane customer base (exclusive of acquisitions), an expansion of several corporate alliance programs, an increase in referrals, direct marketing activity and field sales initiatives.
During fiscal 2011 we lost 1.4% of our home heating oil accounts to natural gas which compares to losses to natural gas of 1.2% for fiscal 2010 and 1.6% for fiscal 2009 . We believe that conversions to natural gas have increased and may continue to do so as natural gas has become significantly less expensive than home heating oil on an equivalent BTU basis.
Consolidated Results of Operations
The following is a discussion of the consolidated results of operations of the Partnership and its subsidiaries, and should be read in conjunction with the historical Financial and Operating Data and Notes thereto included elsewhere in this Annual Report.
 
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Fiscal Year Ended September 30, 2011
Compared to the Fiscal Year Ended September 30, 2010
Volume
For fiscal 2011, retail volume of home heating oil and propane increased by 45.3 million gallons, or 14.6%, to 355.6 million gallons, as compared to 310.3 million gallons for fiscal 2010. Volume of other petroleum products increased by 6.3 million gallons, or 16.9%, to 43.1 million gallons for fiscal 2011, as compared to 36.8 million gallons for fiscal 2010, due to the additional volume from acquisitions. An analysis of the change in the retail volume of home heating oil and propane, which is based on management’s estimates, sampling and other mathematical calculations, is found below:

(in millions of gallons)	  	Heating Oil
and  Propane	 	
Volume—Fiscal 2010	  	 	310.3	  	
Acquisitions	  	 	39.7	  	
Impact of colder temperatures	  	 	25.0	  	
Net customer attrition—Residential	  	 	(11.7	) 	
Decline in Commercial / Bid / COD (Cash on delivery)	  	 	(4.8	) 	
Conservation and other	  	 	(2.9	) 	
 	  	 	 	 	
Change	  	 	45.3	  	
Volume—Fiscal 2011	  	 	355.6	  	
 	  	 	 	 	
For those locations that the Partnership operated in both periods, which we sometimes refer to as the “base business” (i.e. excluding acquisitions), temperatures in our geographic areas of operations for fiscal 2011 were 8.6% colder than fiscal 2010 and 0.4% warmer than normal, as reported by the National Oceanic Atmospheric Administration (“NOAA”). For fiscal 2011, net customer attrition was 3.5%. In addition, 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 43.6% of total home heating oil volume sales for fiscal 2011, as compared to 42.0% for fiscal 2010. Accordingly, the percentage of home heating oil volume sold to residential price-protected customers decreased to 43.7% for fiscal 2011, as compared to 44.1% for fiscal 2010. For fiscal 2011, sales to commercial/industrial customers represented 12.7% of total home heating oil volume sales, as compared to 13.8% for fiscal 2010.
Product Sales
For fiscal 2011, product sales increased $364.4 million, or 35.4%, to $1.393 billion, as compared to $1.028 billion for fiscal 2010 due to the previously described increases in volume and higher product selling prices, which increased in response to higher per gallon wholesale product costs.
Installation and Service Sales
For fiscal 2011, installation and service sales increased $14.0 million, or 7.6%, to $198.4 million, as compared to $184.4 million for fiscal 2010 due largely to the additional revenue from acquisitions. The base business service revenue was essentially unchanged from the prior year, as price increases on service offerings offset a decline due to a reduction in the customer base.
Cost of Product
For fiscal 2011, cost of product increased $323.2 million, or 44.0%, to $1.058 billion, as compared to $734.6 million for fiscal 2010, due to higher volume and increased per gallon wholesale product costs of $0.5118 for home heating oil and propane and $0.7486 for other petroleum products.
 
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Gross Profit Product
The table below calculates the Partnership’s per gallon margins and reconciles product gross profit for home heating oil and propane and other petroleum products. We believe the change in home heating oil and propane margins should be evaluated before the effects of increases or decreases in the fair value of derivative instruments, as we believe that realized per gallon margins should not include the impact of non-cash changes in the market value of hedges before the settlement of the underlying transaction. On that basis, home heating oil and propane margins for fiscal 2011 decreased by $0.0042 per gallon, or 0.5%, to $0.9122 per gallon, from $0.9164 per gallon in fiscal 2010. Our fiscal 2010 and fiscal 2011 acquisitions have typically had a different per gallon gross profit margin profile and operating cost structure than our base business. Generally, the per gallon margins from our recent acquisitions have been lower than the base business. Excluding acquisitions, home heating oil and propane margins rose by $0.0044 per gallon, or 0.5% versus the prior-year period. Product sales and cost of product include home heating oil, propane, other petroleum products and liquidated damages billings.

 	  	Fiscal Year Ended	 	
 	  	September 30, 2011	 	  	September 30, 2010	 	
 	  	Amount (000)	 	  	Per
Gallon	 	  	Amount (000)	 	  	Per
Gallon	 	
Home Heating Oil and Propane	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Volume (in millions of gallons)	  	 	355.6	  	  	 	 	 	  	 	310.3	  	  	 	 	 	
 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Sales	  	$	1,258.0	  	  	$	3.5379	  	  	$	940.4	  	  	$	3.0303	  	
Cost	  	$	933.6	  	  	$	2.6257	  	  	$	656.0	  	  	$	2.1139	  	
 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Gross Profit	  	$	324.4	  	  	$	0.9122	  	  	$	284.4	  	  	$	0.9164	  	

 	  	Amount (000)	 	  	Per
Gallon	 	  	Amount (000)	 	  	Per
Gallon	 	
Other Petroleum Products	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Volume (in millions of gallons)	  	 	43.1	  	  	 	 	 	  	 	36.8	  	  	 	 	 	
 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Sales	  	$	134.9	  	  	$	3.1314	  	  	$	88.0	  	  	$	2.3887	  	
Cost	  	$	124.2	  	  	$	2.8821	  	  	$	78.6	  	  	$	2.1336	  	
 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Gross Profit	  	$	10.7	  	  	$	0.2493	  	  	$	9.4	  	  	$	0.2552	  	

 	  	Amount (000)	 	  	 	 	  	Amount (000)	 	  	 	 	
Total Product	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Sales	  	$	 1,392.9	  	  	 	 	 	  	$	 1,028.4	  	  	 	 	 	
Cost	  	$	1,057.8	  	  	 	 	 	  	$	734.6	  	  	 	 	 	
 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Gross Profit	  	$	335.1	  	  	 	 	 	  	$	293.8	  	  	 	 	 	
 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
During the heating season of fiscal 2011, wholesale product costs continued to escalate, which limited our ability to expand per gallon margins. Conversely, during the heating season of fiscal 2010, wholesale product costs declined, which largely contributed to the Partnership’s ability to expand its home heating oil and propane margins during this period, as wholesale prices decreased more rapidly than our retail prices. If wholesale product costs continue to escalate, our ability to maintain and/or expand margins may be diminished and our profitability may be adversely impacted.
For fiscal 2011, total product gross profit increased by $41.3 million to $335.1 million, compared to $293.8 million for fiscal 2010, as the impact of higher home heating oil and propane volume ($41.3 million) and the additional gross profit from other petroleum products of ($1.2 million) was partially offset by lower home heating oil and propane per gallon margins ($1.2 million).
Cost of Installations and Service
For fiscal 2011, cost of installation and service increased by $10.1 million, or 6.0%, to $179.6 million, compared to $169.5 million for fiscal 2010, as a $12.4 million increase due to fiscal 2010 and fiscal 2011 acquisitions was partially offset by a $2.3 million decline in our base business, as we reduced service costs in response to a reduction in the customer base.
Installation costs increased by $4.0 million to $59.8 million, or 85.0% of installation sales, during fiscal 2011, versus $55.8 million, or 85.4% of installation sales during fiscal 2010, due to acquisitions ($4.6 million). Service expenses increased by $6.1 million to $119.8 million, or 93.5% of service sales, during fiscal 2011, from $113.7 million in fiscal 2010, or 95.5% of sales, due to acquisitions ($7.8 million). For fiscal 2011, we achieved a combined profit from service and installation of $18.9 million, compared to a combined profit of $14.9 million for
 
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fiscal 2010. This improvement of $4.0 million can be attributed to acquisitions ($1.8 million) and an increase in service and installation profit of $2.2 million in the base business. Management views the service and installation department on a combined basis because many overhead functions and direct expenses such as service technician time cannot be separated or precisely allocated to either service or installation billings.
(Increase) Decrease in the Fair Value of Derivative Instruments
During fiscal 2011, the change in the fair value of derivative instruments resulted in a $2.6 million charge due to the expiration of certain hedged positions (a $4.9 million credit), and a decrease in market value for unexpired hedges (a $7.5 million charge).
During fiscal 2010, the change in the fair value of derivative instruments resulted in a $5.6 million increase due to the expiration of certain hedged positions (a $9.2 million credit) and a decrease in market value for unexpired hedges (a $3.5 million charge).
Delivery and Branch Expenses
For fiscal 2011, delivery and branch expenses increased $32.1 million, or 14.7%, to $250.8 million, compared to $218.6 million for fiscal 2010. Acquisitions accounted for $20.0 million of the higher delivery and branch expenses. In the base business, delivery and branch expenses increased by $12.0 million due to higher delivery expenses of $3.2 million associated with the increase in volume and the numerous snow storms experienced during fiscal 2011 along with an increase in bad debt expense and credit card fees of $5.3 million associated with the rise in sales. The Partnership has increased its reserve rate for doubtful accounts for fiscal 2011, compared to fiscal 2010, in response to an 11 day increase in the days sales outstanding, increased volume due to colder temperatures and higher selling prices. Insurance claims expense also rose by $3.3 million due to an increase in reserves for prior year claims and higher current year claim expense resulting from the extreme winter weather.
Depreciation and Amortization
For fiscal 2011, depreciation and amortization expenses were $17.9 million, compared to $15.7 million for fiscal 2010.
Depreciation expense was higher by $1.4 million due primarily to additional depreciation expense from property and equipment acquired in connection with the fiscal 2011 and fiscal 2010 acquisitions. Amortization expense was higher by $0.8 million as the additional amortization expense from the fiscal 2011 and 2010 acquisitions of $4.5 million was partially offset by a decline in amortization expense attributable to customer lists acquired in fiscal 2001, 2003 and 2004 with either a 7 or 10 year life that became fully amortized in fiscal 2010 and fiscal 2011.
General and Administrative Expenses
For fiscal 2011, general and administrative expenses decreased by $0.7 million to $20.7 million, from $21.4 million for fiscal 2010. Lower acquisition related expenses of $0.3 million and lower pension expense relating to the Partnership’s frozen defined benefit pension plan of $0.8 million were offset by an increase in profit sharing expense of $0.7 million. Pension expense declined as a higher base of pension assets resulted in a higher assumed return in 2011, compared to 2010, and profit sharing expense increased largely due to an increase in Adjusted EBITDA.
The Partnership accrues approximately 6% of adjusted EBITDA as defined in its profit sharing plan for distribution to its employees, which amount is payable when the Partnership achieves actual adjusted EBITDA of at least 70% of the amount budgeted. The dollar amount of the profit sharing pool is subject to increases and decreases in line with increases and decreases in adjusted EBITDA.
Interest Expense
For fiscal 2011, interest expense increased by $1.4 million, or 9.7% to $15.7 million, compared to $14.3 million in fiscal 2010. This reflects an increase in average long-term debt of $25.7 million and a decrease in the weighted average long-term borrowing rate from 10.25% to 9.07%, which resulted in an increase in interest expense of $1.1 million. In November 2010, the Partnership issued $125 million of 8.875% Senior Notes due 2017 and repaid $82.5 million of 10.25% Senior Notes due 2013.
In addition, during fiscal 2011, the Partnership borrowed an average of $15.4 million under its revolving credit facility, or $11.8 million higher than fiscal 2010, which drove an increase in interest expense of $0.5 million, despite a decline in the interest rate on these borrowings from 5.75% to 4.30%.
Interest Income
For fiscal 2011, interest income increased $1.4 million to $4.9 million, as compared to $3.5 million for fiscal 2010, due to higher finance charge income from acquisitions and on higher past due accounts receivables balances.
 
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Amortization of Debt Issuance Costs
For fiscal 2011, amortization of debt issuance costs decreased slightly to $2.4 million, as compared to $2.7 million in fiscal 2010.
Loss on Redemption of Debt
In November 2010, the Partnership issued $125.0 million of Senior Notes due 2017. The Notes accrue interest at a rate of 8.875% and were priced at 99.350% for total gross proceeds of $124.2 million. A portion of the proceeds were used to redeem all of the remaining $82.5 million in face value of our 10.25% Senior Notes due 2013, at an average price of $101.70 per $100 of principal plus accrued interest, with the remainder used for general partnership purposes. The Partnership recorded a loss of $1.7 million for this transaction.
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 on this transaction.
Income Tax Expense
For fiscal 2011, income tax expense increased by $7.1 million, to $22.7 million, from $15.6 million for fiscal 2010, primarily due to the non-recurrence of a $3.9 million benefit recorded in 2010 from the release of opening valuation allowance and also from higher book income from continuing operations before taxes in 2011 compared to 2010. The Partnership’s effective tax rate rose to 48.3% in fiscal 2011 from 35.6% for fiscal 2010 largely due to this same 2010 opening valuation allowance release, which reduced the effective tax rate in 2010 by 8.9%. The current portion of income tax expense in 2011 was $6.9 million or 14.6% of book income from continuing operations before taxes compared to $2.3 million, or 5.2% of book income, in 2010. The increase from 2010 to 2011 in both the amount and the percentage of current income tax expense is primarily due to the utilization by December 31, 2010 of most of the Partnership’s unlimited federal net operating loss carry forwards.
Net Income (Loss)
For fiscal 2011, net income decreased $4.0 million to $24.3 million, from $28.3 million for fiscal 2010, as the increase in operating income of $3.9 million was more than offset by an increase in income tax expense of $7.1 million.
Adjusted EBITDA
For fiscal 2011, Adjusted EBITDA increased by $13.8 million, or 20.1%, to $82.5 million as the impact of colder temperatures of 8.6% and a $16.9 million increase in Adjusted EBITDA provided by fiscal 2011 and 2010 acquisitions were somewhat offset by net customer attrition in the base business, higher delivery and branch expenses attributable to the numerous snowstorms in our marketing areas, an increase in bad debt expense and credit card processing fees due to the increase in sales (driven largely by the increase in wholesale product cost) and an increase in insurance claims expense due in part to the severe winter weather. In fiscal 2010, the impact of fiscal 2010 acquisitions reduced Adjusted EBITDA by $3.6 million as the fiscal 2010 acquisitions were completed after 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.
 
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EBITDA and Adjusted EBITDA are calculated as follows:

 	  	Fiscal Year Ended September 30,	 	
(in thousands)	  	2011	 	 	2010	 	
Income from continuing operations	  	$	24,344	  	 	$	28,320	  	
Plus:	  	 	 	 	 	 	 	 	
Income tax expense	  	 	22,723	  	 	 	15,632	  	
Amortization of debt issuance cost	  	 	2,440	  	 	 	2,680	  	
Interest expense, net	  	 	10,840	  	 	 	10,820	  	
Depreciation and amortization	  	 	17,884	  	 	 	15,745	  	
 	  	 	 	 	 	 	 	 	
EBITDA(a) from continuing operations	  	 	78,231	  	 	 	73,197	  	
(Increase) / decrease in the fair value of derivative instruments	  	 	2,567	  	 	 	(5,622	) 	
Loss on redemption of debt	  	 	1,700	  	 	 	1,132	  	
 	  	 	 	 	 	 	 	 	
Adjusted EBITDA(a)	  	 	82,498	  	 	 	68,707	  	
 	 	 	
Add / (subtract)	  	 	 	 	 	 	 	 	
Income tax (expense)	  	 	(22,723	) 	 	 	(15,632	) 	
Interest expense, net	  	 	(10,840	) 	 	 	(10,820	) 	
Provision for losses on accounts receivable	  	 	10,388	  	 	 	5,279	  	
Increase in accounts receivables	  	 	(31,593	) 	 	 	(4,570	) 	
Increase in inventories	  	 	(13,189	) 	 	 	(2,012	) 	
Decrease in customer credit balances	  	 	(1,776	) 	 	 	(9,250	) 	
Change in deferred taxes	  	 	15,831	  	 	 	13,331	  	
Change in other operating assets and liabilities	  	 	10,806	  	 	 	(604	) 	
 	  	 	 	 	 	 	 	 	
Net cash provided by operating activities	  	$	39,402	  	 	$	44,429	  	
 	  	 	 	 	 	 	 	 	
Net cash used in investing activities	  	$	(15,928	) 	 	$	(73,956	) 	
 	  	 	 	 	 	 	 	 	
Net cash provided by (used in) financing activities	  	$	2,253	  	 	$	(104,571	) 	

(a)	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.	
 
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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 and propane decreased by 41.3 million gallons, or 11.7%, to 310.3 million gallons, compared to 351.6 million gallons for fiscal 2009. Volume of other petroleum products declined by 0.5 million gallons, or 1.4%, to 36.8 million gallons for fiscal 2010, 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, and propane which is based on management’s estimates, sampling and other mathematical calculations, is found below:

(in millions of gallons)	  	Heating Oil
and  Propane	 	
Volume—Fiscal 2009	  	 	351.6	  	
Impact of warmer temperatures	  	 	(31.8	) 	
Net customer attrition—residential / commercial	  	 	(12.4	) 	
Acquisitions	  	 	3.8	  	
Other	  	 	(0.9	) 	
 	  	 	 	 	
Change	  	 	(41.3	) 	
 	  	 	 	 	
Volume—Fiscal 2010	  	 	310.3	  	
 	  	 	 	 	
In our base business, 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 NOAA. For fiscal 2010, net customer attrition excluding acquisitions, which were completed after the heating season, was 4.7%. Due to the significant increase in the price per gallon of home heating oil and propane 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 and propane 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 11.7% decrease in home heating oil and propane 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 propane and other petroleum products was reduced by the 11.7% decline in home heating oil and propane volume.
 
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Gross Profit Product
The table below calculates the Partnership’s per gallon margins and reconciles product gross profit for home heating oil and propane and other petroleum products. We believe the change in home heating oil and propane margins should be evaluated before the effects of increases or decreases in the fair value of derivative instruments, as we believe that realized per gallon margins should not include the impact of non-cash changes in the market value of hedges before the settlement of the underlying transaction. On that basis, home heating oil and propane margins for fiscal 2010 increased by $0.0198 per gallon, or 2.2%, to $0.9164 per gallon, from $0.8966 per gallon in fiscal 2009. Product sales and cost of product include home heating oil and propane, other petroleum products and liquidated damages billings.

 	  	Fiscal Year Ended	 	
  	  	September 30, 2010	 	  	September 30, 2009	 	
 	  	Amount
(000)	 	  	Per
Gallon	 	  	Amount
(000)	 	  	Per
Gallon	 	
Home Heating Oil and Propane	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Volume (in millions of gallons)	  	 	310.3	  	  	 	 	 	  	 	351.6	  	  	 	 	 	
 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Sales	  	$	940.4	  	  	$	3.0303	  	  	$	960.0	  	  	$	2.7302	  	
Cost	  	$	656.0	  	  	$	2.1139	  	  	$	644.7	  	  	$	1.8336	  	
 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Gross Profit	  	$	284.4	  	  	$	0.9164	  	  	$	315.3	  	  	$	0.8966	  	

 	  	Amount
(000)	 	  	Per
Gallon	 	  	Amount
(000)	 	  	Per
Gallon	 	
Other Petroleum Products	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Volume (in millions of gallons)	  	 	36.8	  	  	 	 	 	  	 	37.4	  	  	 	 	 	
 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Sales	  	$	88.0	  	  	$	2.3887	  	  	$	72.8	  	  	$	1.9465	  	
Cost	  	$	78.6	  	  	$	2.1336	  	  	$	63.5	  	  	$	1.6979	  	
 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Gross Profit	  	$	9.4	  	  	$	0.2552	  	  	$	9.3	  	  	$	0.2487	  	

 	  	Amount
(000)	 	  	 	 	  	Amount
(000)	 	  	 	 	
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 and propane per gallon margins ($6.2 million) was more than offset by the impact of lower home heating oil volume and propane ($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, 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.
 
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(Increase) Decrease in the Fair Value of Derivative Instruments
During fiscal 2010, the change in the fair value of derivative instruments resulted in 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 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 and propane volume which mitigated the impact of inflationary pressures on operating expenses. On a cents per gallon basis, delivery and branch expenses increased 6.6 cents per gallon or 10.5%, from 63.8 cents for fiscal 2009 to 70.4 cents for fiscal 2010 due to the fixed nature of certain operating expenses that could not be adjusted in spite of the 11.7% decline in home heating oil and propane volume. Our fiscal 2010 acquisitions, which were completed after the heating season incurred operating costs without generating any heating season volume, which adversely impacted the year over year operating cost comparison by 1.8 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, 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 investment 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. The dollar amount of the profit sharing pool is subject to increases and decreases in line with increases and decreases in adjusted EBITDA.
Interest Expense
For fiscal 2010, interest expense decreased by $3.5 million, or 19.7 % to $14.3 million, compared to $17.8 million for fiscal 2009. Over the last two fiscal years, the Partnership 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 of 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.
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, 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.
 
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Amortization of Debt Issuance Costs
For fiscal 2010, amortization of debt issuance costs decreased slightly to $2.7 million, 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 for this transaction.
Income Tax Expense (Benefit)
Income tax expense increased by $73.2 million in fiscal 2010 compared to fiscal 2009 primarily due to an $82.5 million lower benefit from the release of the 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 2009 that these deferred tax assets should be recognized. For fiscal 2009 this benefit was $86.4 million, representing the majority of our opening valuation allowance in that year.
This decreased benefit of $82.5 million was partially offset in fiscal 2010 by $7.8 million in lower deferred tax expense and $1.5 million in lower current tax expense compared to fiscal 2009. These lower 2010 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%.
Net Income (Loss)
For fiscal 2010, net income of $28.3 million was recorded, compared to 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, 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.
 
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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 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	  	 	(4,750	) 	 	 	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 operating activities	  	 	$44,249	  	 	 	$78,455	  	
 	  	 	 	 	 	 	 	 	
Net cash used in investing activities	  	$	(73,956	) 	 	$	(7,568	) 	
 	  	 	 	 	 	 	 	 	
Net cash used in financing activities	  	$	(104,571	) 	 	$	(54,535	) 	

(a)	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.	
 
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DISCUSSION OF CASH FLOWS
We use the indirect method to prepare our Consolidated Statements of Cash Flows. Under this method, we reconcile net income to cash flows provided by operating activities by adjusting net income for those items that impact net income but may not result in actual cash receipts or payment during the period.
Operating Activities
Due to the seasonal nature of our business, cash is generally used in operations during the winter (our first and second fiscal quarters) as we require additional working capital to support the high volume of sales during this period, and cash is generally provided by operating activities during the spring and summer (our third and fourth quarters) when customer payments exceed deliveries.
During fiscal 2011, cash provided by operating activities decreased by $5.0 million to $39.4 million, when compared to $44.4 million of cash provided by operating activities during fiscal 2010, as a favorable change in cash generated from operations of $14.3 million, the timing of cash receipts from budget customers of $7.5 million, increases in accruals for insurance, interest, profit sharing and accounts payable totaling $11.2 million and lower contributions to the Partnership’s frozen pension plan of $9.9 million was reduced by a decline of $11.9 million in the cash benefit relating to the payment for hedging options, an increase in inventory of $11.2 million (largely due to an increase in price) and an increase in cash needs to fund accounts receivable of $27.0 million. In fiscal 2010, the Partnership structured its option purchases such that the cost of the option will be paid as it expired rather than at the time the hedge is entered into. The increase in accounts receivable can be attributed to an increase in volume due to acquisitions and colder temperatures, as well as an increase in selling prices. Days sales outstanding as of September 30, 2011 were 61 days as compared to 50 days at September 30, 2010 and 50 days at September 30, 2009. The impact of a colder third fiscal quarter coupled with an increase in wholesale product costs resulted in both budget and non-budget customers owing more at September 30, 2011 than at September 30, 2010.
During fiscal 2010, cash provided by operating activities declined by $34.1 million to $44.4 million, 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 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 is 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 receivable increased by $4.6 million during fiscal 2010 which compares to a decrease of $26.7 million in fiscal 2009. 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 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.
Investing Activities
Our capital expenditures for fiscal 2011 totaled $6.4 million, as we invested in computer hardware and software ($2.3 million), refurbished certain physical plants ($1.9 million), expanded our propane operations ($0.9 million) and made additions to our fleet and other equipment ($1.3 million). We also completed four acquisitions for $9.7 million and allocated $4.2 million of the gross purchase price to intangible assets (including $0.2 million to goodwill), $3.2 million to fixed assets, $0.4 million to other long-term assets and $1.9 to working capital.
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 price to intangible assets (including $16.1 million to goodwill), $7.6 million to fixed assets and $2.9 million to other net liabilities.
Our capital expenditures for fiscal 2009 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 (including $0.9 million to goodwill) and $0.6 million to fleet. We paid $ 3.4 million in cash and assumed net working capital credits of $ 0.6 million.
 
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Financing Activities
During fiscal 2011, we sold $125 million of 8.875% Senior Notes due 2017 at a price of 99.350%. A portion of the net proceeds were used on December 20, 2010, to repurchase $82.5 million in face value of 10.25% Senior Notes due February 2013. After paying expenses of $3.8 million and a call premium of $1.4 million, our cash balance increased by $36.5 million, which was utilized for general partnership purposes. In June 2011, we amended our bank agreement and extended it to June 2016. In connection with this extension we paid fees of $2.5 million. Also during the fiscal 2011, we paid distributions of $20.7 million, including $0.13 million paid to our general partner as incentive distributions (as provided for in our Partnership Agreement), repurchased 2.1 million units for $10.9 million, borrowed $88.4 million under our revolving credit facility and repaid $88.4 million of these borrowings during the period.
The Partnership repurchased 8.1 million common units for $33.2 million in connection with the unit repurchase plan program and paid distributions of $20.4 million during fiscal 2010. 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 revolving credit facility agreement and spent $2.3 million to purchase 637,285 common units in connection with our unit repurchase program.
FINANCING AND SOURCES OF LIQUIDITY
Liquidity and Capital Resources
Our primary liquidity needs are to fund our working capital requirements, capital expenditures, pay distributions and to provide funds to make acquisitions and to repurchase our units. 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 as of September 30, 2011, or a combination thereof. To the extent future capital requirements exceed cash on hand plus cash flows from operating activities, we anticipate that working capital will be financed by our revolving credit facility, as discussed below, and repaid from subsequent seasonal reductions in inventory and accounts receivable. If we require additional capital, we may seek to offer and sell debt or equity securities under our $250 million shelf registration statement.
In June 2011 and November 2011, we amended and restated our asset based revolving facility, under which our subsidiary, Petroleum Heat and Power Co., is the borrower and we are an additional loan party, extending the maturity date from July 2012 to June 2016. The amended facility provides us with the ability to borrow up to $250 million ($350 million during the heating season from November through April of each year) for working capital purposes (subject to certain borrowing base limitations and coverage ratios), including the issuance of up to $100 million in letters of credit. We can increase the facility size by $100 million without the consent of the bank group. However, the bank group is not obligated to fund the $100 million increase. If the bank group elects not to fund the increase, we can add additional lenders to the group, with the consent of the Agent, which shall not be unreasonably withheld. Obligations under the revolving credit facility are guaranteed by us and our subsidiaries and secured by liens on substantially all of our assets, including accounts receivable, inventory, general intangibles, real property, fixtures and equipment. As of September 30, 2011, $46.7 million in letters of credit were outstanding, of which $46.4 million are for current and future insurance reserves and bonds and $0.3 million are for seasonal inventory purchases and other working capital purposes.
Under the terms of the revolving credit facility, we must maintain at all times either availability (borrowing base less amounts borrowed and letters of credit issued) of 12.5% of the maximum facility size or a fixed charge coverage ratio of not less than 1.1, which is calculated based upon Adjusted EBITDA. As of September 30, 2011, availability, as defined in the amended and restated revolving credit facility agreement, was $162.4 million and we were in compliance with the fixed charge coverage ratio. Any failure to comply with these covenants could have a material adverse effect on our liquidity and results of operations. For additional information concerning the revolving credit facility, see Note 6 of the Notes to the Condensed Consolidated Financial Statements.
The Partnership’s scheduled interest payments for fiscal 2012 are $11.1 million on its Senior Notes. Annual maintenance capital expenditures for fixed assets are estimated to be approximately $4.0 to $6.0 million, excluding the capital requirements for leased fleet. In addition, we plan to invest an estimated $2.0 million in our propane operations for fleet and tank purchases. 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
 
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minimum cash contributions to fund its frozen defined benefit pension obligations of a total of approximately $15.4 million over the next five fiscal years. We anticipate paying distributions of approximately $20 million in fiscal 2012. We will continue to seek strategic acquisitions and we may continue to repurchase common units as authorized under our unit repurchase plan. From October 1, 2011 to November 30, 2011, we have repurchased 0.4 million common units at a cost of $2.2 million. In addition, we completed two acquisitions for an aggregate cost of approximately $24.1 million, including working capital of $4.5 million.
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 revolving credit facility, we must have availability of at least 17.5% of the maximum facility size and a fixed charge coverage ratio of 1.15 to pay any distribution. This test restricts the amount of cash that we can use to pay a distribution with respect to any fiscal quarter. The Board of Directors of our General Partner reviews the level of Available Cash each quarter based upon information provided by management.
On October 25, 2011, we declared a quarterly distribution of $0.0775 per unit, or $0.31 per unit on an annualized basis, on all common units in respect of the fourth quarter of fiscal 2011 payable on November 14, 2011 to holders of record on November 4, 2011. In accordance with our Partnership Agreement, the amount of distributions in excess of the minimum quarterly distribution of $0.0675, are distributed 90% to the holders of common units and 10% to the holders of the general partner units (until certain distribution levels are met), subject to the management incentive compensation plan. As a result, $5.0 million was paid to the common unit holders, $0.06 million was paid to the general partner and $0.04 million was paid to management pursuant to the management incentive compensation plan.
(See Part II—Item 5. Market for Registrant’s Units and Related Matters—Partnership Distribution Provisions and Note 4 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, 2011.
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, 2011 (in thousands):

 	  	Payments Due by Fiscal Year	 	
 	  	 	 	  	 	 	  	2013 and	 	  	2015 and	 	  	 	 	
 	  	Total	 	  	2012	 	  	2014	 	  	2016	 	  	Thereafter	 	
Long-term debt obligations	  	$	125,000	  	  	$	—  	  	  	$	—  	  	  	$	—  	  	  	$	125,000	  	
Operating lease obligations (a)	  	 	57,949	  	  	 	11,826	  	  	 	21,212	  	  	 	14,991	  	  	 	9,920	  	
Purchase obligations (b)	  	 	14,983	  	  	 	10,343	  	  	 	4,592	  	  	 	48	  	  	 	—  	  	
Interest obligations (c)	  	 	69,337	  	  	 	11,094	  	  	 	22,188	  	  	 	22,188	  	  	 	13,867	  	
Long-term liabilities reflected on the balance sheet (d)	  	 	3,996	  	  	 	350	  	  	 	700	  	  	 	700	  	  	 	2,246	  	
 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
 	  	 	$271,265	  	  	 	$33,613	  	  	 	$48,692	  	  	 	$37,927	  	  	 	$151,033	  	

(a)	Represents various operating leases for office space, trucks, vans and other equipment with third parties.	
(b)	Represents non-cancelable commitments as of September 30, 2011 for operations such as customer related invoice and statement processing and voice and data phone/computer services.	
(c)	Reflects 8.875% interest obligations on our $125.0 million senior notes (excluding discounts) due February 2017 and the unused commitment fee on the revolving credit facility.	
(d)	Reflects long-term liabilities excluding a pension accrual of approximately $15.4 million. We estimate minimum cash contributions of approximately $3.4 million for fiscal 2012 and approximately $3.0 million for each of the fiscal years 2013 to 2016.	
 
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Recent Accounting Pronouncements
In May 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2011-04, Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. generally accepted accounting principles (“U.S. GAAP”) and the International Financial Reporting Standards (“IFRS”), that results in a consistent definition of fair value and common requirements for measurement of and disclosure about fair value. The new guidance clarifies and changes some fair value measurement principles and disclosure requirements under U.S. GAAP. Among them is the clarification that the concepts of highest and best use and valuation premise in a fair value measurement, should only be applied when measuring the fair value of nonfinancial assets. Additionally, the new guidance requires quantitative information about unobservable inputs, and disclosure of the valuation processes used and narrative descriptions with regard to fair value measurements within the Level 3 categorization of the fair value hierarchy. The new guidance is effective for interim and annual reporting periods beginning after December 15, 2011, with early adoption prohibited. The adoption of this new guidance is not expected to have a material impact on the Partnership’s Consolidated Financial Statements.
In June 2011, the FASB issued ASU No. 2011-05, Comprehensive Income (Topic 220): Presentation of Comprehensive Income, and subsequently issued a proposal to defer the requirement to separately present within net income reclassification adjustments of items out of accumulated other comprehensive income. This standard eliminates the option to present items of other comprehensive income (“OCI”) as part of the statement of changes in stockholders’ equity, and instead requires either OCI presentation and net income in a single continuous statement to the statement of operations, or as a separate statement of comprehensive income. ASU No. 2011-05 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011, with early adoption permitted. The Partnership is required to adopt this update in the first quarter of fiscal year 2013. The adoption of ASU No. 2011-05 will not impact our results of operations or the amount of assets and liabilities reported.
In September 2011, the FASB issued ASU No. 2011-08, Intangibles-Goodwill and Other (Topic 350): Testing Goodwill for Impairment. This standard simplifies how entities test goodwill for impairment by providing for an optional qualitative assessment in determining whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount, as a basis for determining whether it is necessary to perform the first step, of the two-step goodwill impairment test. The new guidance is effective for annual and interim goodwill impairment tests performed in fiscal years beginning after December 15, 2011, with early adoption permitted. The Partnership is required to adopt this update in fiscal year 2012. The adoption of ASU No. 2011-08 will not impact our results of operations or the amount of assets and liabilities reported.
In September 2011, the FASB issued ASU No. 2011-09, Compensation—Retirement Benefits—Multiemployer Plans (Subtopic 715-80): Disclosures about an Employer’s Participation in a Multiemployer Plan. This standard requires employers that participate in multiemployer pension plans to provide additional quantitative and qualitative disclosures such as significant multiemployer plan names, identifying number, employer contributions, an indication of the plan’s funded status, and the nature of the employer commitments to the plan. The new guidance is effective for annual periods for fiscal years ending after December 15, 2011, with early adoption permitted. The Partnership is required to adopt this update in fiscal year 2012. The adoption of ASU No. 2011-09 will not impact our results of operations or the amount of assets and liabilities reported.
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 of the Notes 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, 2011, we had $52.3 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 2011 would have increased by approximately $0.4 million.
 
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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, 2011, we had $199.3 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, 2011. 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 30 years. Net property and equipment was $47.1 million at September 30, 2011. 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 2011 would have increased by approximately $1.4 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. 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.
 
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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 rate used for fiscal 2011 would have increased pension expense by approximately $0.2 million and would have increased the pension liability by another $1.7 million. The discount rate used to determine net periodic pension expense was 4.7% in 2011, 5.4% in 2010, and 7.6% in 2009. The discount rate used in determining end of year pension obligations was 4.35% in 2011, 4.7% in 2010, and 5.4% in 2009. 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 investment advisors. The long-term rate of return assumption used for determining net periodic pension expense for fiscal 2011 and 2010 was 7.75% respectively. A further 25 basis point decrease in the expected return on assets would have increased pension expense in fiscal 2011 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, 2011, $33.0 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
The allowance for doubtful accounts, which includes the allowance for long-term receivables, is the Partnership’s best estimate of the amount of trade receivables that may not be collectible. The allowance is determined at an aggregate level (as opposed to account by account) by grouping accounts based on the type of account and its receivable aging. The allowance is based on both quantitative and qualitative factors, including historical loss experience, historical collection patterns, overdue status, aging trends, and current economic conditions. The Partnership has an established process to periodically review current and past due trade receivable balances to determine the adequacy of the allowance. No single statistic or measurement determines the adequacy of the allowance. The total allowance reflects management’s estimate of losses inherent in its trade receivables at the balance sheet date. Different assumptions or changes in economic conditions could result in material changes to the allowance for doubtful accounts.
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, 2011, we had approximately $42.7 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.
 
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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, 2011, we had outstanding borrowings totaling $125.0 million (excluding discounts), 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, 2011, the potential impact on our hedging activity would be to increase the fair market value of these outstanding derivatives by $7.2 million to a fair market value of $7.7 million; and conversely a hypothetical ten percent decrease in the cost of product would decrease the fair market value of these outstanding derivatives by $4.4 million to a fair market value of $(3.9) 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, 2011. Based on that evaluation, such principal executive officer and principal financial officer concluded that the Partnership’s disclosure controls and procedures were effective as of September 30, 2011 at the reasonable level of assurance. For purposes of Rule 13a-15(e), the term  disclosure controls and procedures  means controls and other procedures of an issuer that are designed to ensure that information required to be disclosed by the issuer in the reports that it files or submits under the Act (15 U.S.C. 78a et seq.) is recorded, processed, summarized and reported, within the time periods specified in the Commission’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Act is accumulated and communicated to the issuer’s management, including its principal executive and principal financial officer, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.
(b) 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, 2011. The effectiveness of our internal control over financial reporting as of September 30, 2011 has been audited by our independent registered public accounting firm, as stated in their report which is included herein.
(c) Change in Internal Control over Financial Reporting.
No change in the Partnership’s internal control over financial reporting occurred during the Partnership’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect the Partnership’s internal control over financial reporting.
(d) Other.
The 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
 
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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, 2011, 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
Our general partner is Kestrel Heat. The Board of Directors of Kestrel Heat is appointed by its sole member, Kestrel, which is a private equity investment partnership formed by Yorktown Energy Partners VI, L.P., Paul A. Vermylen and other investors.
Kestrel Heat, as our general partner, oversees our activities. Unitholders do not directly or indirectly participate in our management or operation or elect the directors of the general partner. The Board of Directors (sometimes referred to as the “Board”) of Kestrel Heat 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 our 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, 2011, Kestrel Heat and its affiliates owned an aggregate of 12,803,128 common units, representing 19.84% of the issued and outstanding common units, and Kestrel Heat 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 our general partner, for all our debts (to the extent not paid by us), except to the extent that indebtedness or other obligations incurred by us 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 us.
Directors and Executive Officers of the General Partner
Directors are appointed for an indefinite term, subject to the discretion of Kestrel. The following table shows certain information for directors and executive officers of the general partner as of November 30, 2011:

Name	  	Age	 	  	Position	
Paul A. Vermylen, Jr.	  	 	64	  	  	Chairman, Director	
Daniel P. Donovan	  	 	65	  	  	President, Chief Executive Officer and Director	
Richard F. Ambury	  	 	54	  	  	Executive Vice President and Chief Financial Officer	
Steven J. Goldman	  	 	51	  	  	Executive Vice President and Chief Operating Officer	
Richard G. Oakley	  	 	51	  	  	Vice President and Controller	
Henry D. Babcock(1)	  	 	71	  	  	Director	
C. Scott Baxter(1)	  	 	50	  	  	Director	
Bryan H. Lawrence	  	 	69	  	  	Director	
Sheldon B. Lubar	  	 	82	  	  	Director	
William P. Nicoletti (1)	  	 	66	  	  	Director	
 
(1) 	Audit Committee member	
 
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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. (“Meenan”) from 1982 until 1992 and as President of Meenan until 2001, when we acquired Meenan. 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 an 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 the Chairman and 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 the President and Chief Operating Officer of a predecessor general partner, Star Gas LLC (“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, a predecessor general partner. Mr. Ambury was employed by Petroleum Heat and Power Co., Inc. 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 Operations Officer of Kestrel Heat since May 1, 2010 and was Senior Vice President of Operations of Kestrel Heat 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. 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 a consultant to Train, Babcock Advisors LLC, a privately owned registered investment advisor. He joined the firm in 1976, became a partner in 1980, CEO in 1999 and Chairman in 2006. 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 Inc.
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.
 
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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, Scott 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 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 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
Section 303A of the New York Stock Exchange listed company manual provides that limited partnerships are not required to have a majority of independent directors. It is the policy of the Board of Directors that the Board shall at all times have at least three independent 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” has 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 . The Board of Directors has determined that Messrs. Nicoletti, Babcock, and Baxter are independent directors.
 
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Meetings of Directors
During fiscal 2011, the Board of Directors of Kestrel Heat, met five times. All directors attended each meeting except for one meeting where one director did not attend.
Committees of the Board of Directors
Kestrel Heat’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, 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’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 2011, the Audit Committee of Kestrel Heat, LLC met five times. All members attended each meeting except for one meeting which 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 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 2011.
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 2011, all reporting persons complied with the Section 16(a) filing requirements applicable to them, except that Mr. Nicoletti filed a Form 4 after the due date because common units were inadvertently purchased for him pursuant to a brokerage distribution reinvestment program without his knowledge.
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.
 
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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, 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 2011, each person who served as chief financial officer (“CFO”) during fiscal 2011 and the two other most highly compensated executive officers serving at September 30, 2011 (there being no other executive officers who earned more than $100,000 during fiscal 2011) are referred to as the “named executive officers” and are included in the Executive Compensation Table.
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 over time.	
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 criterion to determine compensation. Rather, after subjectively setting compensation based on the policies discussed above under “Compensation Philosophy and Policies” ,  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, 2011, the principal components of compensation for the named executive officers were:
 
 	•	 	base salary;	
 
 	•	 	annual discretionary profit sharing allocation;	
 
 	•	 	management incentive compensation plan; and	
 
 	•	 	retirement and health benefits.	
 
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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.
The majority of the Partnership’s compensation allocation is weighted towards base salary and annual discretionary profit sharing allocation. 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. In addition, during fiscal 2011, an aggregate of $92,255 was paid to the named executive officers under the terms of the Partnership’s management incentive compensation plan and represented a small portion of the executive compensation that was paid to these officers. In the future, the amounts payable to the named executive officers under the management incentive compensation plan will increase, if the Partnership is successful in increasing the overall level of distributions payable to unitholders.
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 over time. 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 and long-term incentive awards provide an incentive to our executives to achieve business objectives that increase our financial performance, which creates unitholder value through continuity of, and increases in, distributions and increases in the market value of the units. 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 criterion 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 2011 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.
 
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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 profit sharing allocations 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 2011 unless the Partnership achieved actual adjusted EBITDA for fiscal 2011 of at least 70% of the amount of budgeted adjusted EBITDA for fiscal 2011. 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 profit sharing 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 profit sharing allocation 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 profit sharing allocations based upon the factors discussed above.
Management Incentive Compensation Plan
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 Partnership believes that the Management Incentive Compensation Plan provides a long-term incentive to its participants because it encourages the Partnership’s management to increase the Partnership’s available cash for distributions in order to trigger the incentive distributions that are only payable if distributions from available cash exceeds certain target distribution levels, with higher percentages of incentive distributions triggered by higher levels of distributions. Such increases are not sustainable on a consistent basis without long-term improvements in the Partnership’s operations.
The pro rata share payable to each participant under the Plan is based on the number of participation points as described under “Fiscal 2011 Compensation Decisions—Management Incentive Compensation 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
 
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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 $260,856 in Incentive Distributions during fiscal 2011, with payments to the named executive officers of approximately $92,255 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 certain executive officers. The present value of accumulated benefits under these frozen defined benefit pension plans for certain 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 2011 Compensation Decisions
For fiscal 2011, 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, 2011 and the percentage increase in his base salary over October 1, 2010. The current base salaries for our named executive officers were determined during fiscal 2011, based upon the factors discussed under the caption “Base Salary.” The increases in such base salaries that were granted in fiscal 2011 were generally intended to reflect continued improvement in the Partnership’s operating results. The average percentage increase in base salary for executives in our peer group was 1.8%.

Name	  	    Salary    	  	Percentage Over Prior Year    	
Daniel P. Donovan	  	$413,100	  	2.0%	
Richard F. Ambury	  	$331,500	  	2.0%	
Steven J. Goldman	  	$321,300	  	2.0%	
Richard G. Oakley	  	$219,200	  	3.0%	
 
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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. For fiscal 2011 the profit sharing amounts reflected in the Summary Compensation Table are 1.0%, 2.2%, 19.1%, and 6.9% higher than fiscal 2010 for Messrs. Donovan, Ambury, Goldman and Oakley, respectively. Mr. Goldman’s increase of 19.1% is due to his serving as the Partnership’s COO for the entire 2011 fiscal year. One of the Partnership’s primary performance measures is adjusted EBITDA for profit sharing purposes. This adjusted EBITDA increased by $11.6 million, or 15.2%, to $87.8 million for fiscal 2011. The average percentage decrease in adjusted EBITDA for companies in our peer group was 0.4%.
Product costs in fiscal 2011 increased by 24 % per gallon versus fiscal 2010, which presented the Partnership with a greater challenge than fiscal 2010, a year in which wholesale product costs increased by 15%. During fiscal 2011, the Partnership completed four acquisitions with 8,800 home heating oil and propane accounts. The total purchase price for these acquisitions was $9.7 million. The Partnership does not have any specific acquisition goals or targets. These acquisitions were not included in anyone’s goals for fiscal 2011.
Messrs. Donovan, Ambury, Goldman and Oakley were instrumental in Star’s acquisition program. In fiscal 2011, the Partnership’s attrition rate improved from 5.0 % to 3.5% due largely to the efforts of Messrs. Donovan and Goldman. The Partnership’s commercial trade credit increased by over $21.0 million due largely to the efforts of Mr. Ambury. Messrs. Donovan, Ambury and Oakley were instrumental in refinancing the Partnership’s public notes and the Partnership’s revolving credit facility both at lower interest rates. Mr. Oakley drove the process of successfully converting the fiscal 2011 acquisitions to the Partnership’s accounting systems.
Management Incentive Compensation Plan
The participation points are 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. No additional participation points were awarded in fiscal 2011.
In fiscal 2011, $92,225 was paid to the named executive officers under the Management Incentive Compensation Plan as indicated in the following chart:

 	  	Fiscal 2011	 	 	Management Incentive	 	
Name	  	Points	 	  	Percentage	 	 	Payments	 	
Daniel Donovan	  	 	300	  	  	 	29.3	% 	 	 	38,175	  	
Richard Ambury	  	 	235	  	  	 	22.9	  	 	 	29,903	  	
Steven Goldman	  	 	150	  	  	 	14.6	  	 	 	19,087	  	
Richard Oakley	  	 	40	  	  	 	3.9	  	 	 	5,090	  	
Other Plan Participants	  	 	300	  	  	 	29.3	  	 	 	38,175	  	
 	  	 	 	 	  	 	 	 	 	 	 	 	
Total	  	 	1,025	  	  	 	100.0	% 	 	 	130,430	  	
 	  	 	 	 	  	 	 	 	 	 	 	 	
Retirement and Health Benefits
There were no changes to the retirement and health benefits applicable to the named executive officers in fiscal 2011.
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.
 
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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 either of 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 $1,993,265 and Mr. Ambury would have received a payment of $1,586,333.
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, 2011.
Paul A. Vermylen, Jr.
Daniel P. Donovan
Henry D. Babcock
C. Scott Baxter
Bryan H. Lawrence
Sheldon B. Lubar
William P. Nicoletti
 
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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. (1)	 	  	Change in
Pension
Value and
Nonqualified
Deferred
Comp.
Earnings (2)	 	  	All Other
Comp.(3)	 	  	Total	 	
Daniel P. Donovan	  	 	2011	  	  	$	412,367	  	  	 	  	 	—  	  	  	 	—  	  	  	$	570,598	  	  	$	67,949	  	  	$	89,722	  	  	$	1,140,636	  	
President and	  	 	2010	  	  	$	395,667	  	  	 	  	 	—  	  	  	 	—  	  	  	$	565,000	  	  	$	85,384	  	  	$	55,760	  	  	$	1,101,811	  	
Chief Executive Officer	  	 	2009	  	  	$	388,333	  	  	 	  	 	—  	  	  	 	—  	  	  	$	615,000	  	  	$	181,947	  	  	$	38,004	  	  	$	1,223,284	  	
 	 	 	 	 	 	 	 	 	 	
Richard F. Ambury	  	 	2011	  	  	$	327,708	  	  	 	  	 	—  	  	  	 	—  	  	  	$	455,000	  	  	$	25,422	  	  	$	64,965	  	  	$	873,095	  	
Chief Financial Officer,	  	 	2010	  	  	$	313,917	  	  	 	  	 	—  	  	  	 	—  	  	  	$	445,000	  	  	$	30,699	  	  	$	47,852	  	  	$	837,468	  	
Treasurer and Executive	  	 	2009	  	  	$	302,500	  	  	 	  	 	—  	  	  	 	—  	  	  	$	485,000	  	  	$	64,798	  	  	$	30,722	  	  	$	883,020	  	
Vice President	  	 	 	 	  	 	 	 	  	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
 	 	 	 	 	 	 	 	 	 	
Steven J. Goldman	  	 	2011	  	  	$	317,625	  	  	 	  	 	—  	  	  	 	—  	  	  	$	430,000	  	  	$	—  	  	  	$	55,001	  	  	$	802,626	  	
Chief Operating Officer and	  	 	2010	  	  	$	298,667	  	  	 	  	 	—  	  	  	 	—  	  	  	$	361,000	  	  	$	—  	  	  	$	44,719	  	  	$	704,386	  	
Executive Vice President	  	 	2009	  	  	$	285,000	  	  	 	  	 	—  	  	  	 	—  	  	  	$	337,000	  	  	$	—  	  	  	$	33,404	  	  	$	655,404	  	
 	 	 	 	 	 	 	 	 	 	
Richard G. Oakley	  	 	2011	  	  	$	212,800	  	  	 	  	 	—  	  	  	 	—  	  	  	$	155,000	  	  	$	34,731	  	  	$	37,137	  	  	$	439,668	  	
Vice President - Controller	  	 	2010	  	  	$	205,600	  	  	 	  	 	—  	  	  	 	—  	  	  	$	145,000	  	  	$	42,887	  	  	$	32,491	  	  	$	425,978	  	
 	  	 	2009	  	  	$	199,600	  	  	 	  	 	—  	  	  	 	—  	  	  	$	150,000	  	  	$	88,066	  	  	$	29,284	  	  	$	466,950	  	
 
(1)	Payable pursuant to the Partnership’s profit sharing pool, which is described under “Compensation Discussion and Analysis – Profit Sharing Allocation.”	
(2)	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.	
(3)	All other compensation is subdivided as follows:	

Name	  	Management
Incentive
Compensation
Plan	 	  	Company Match and
Core Contribution to
401(K) Plan	 	  	Contributions to
Nonqualified  Deferred
Compensation Plan	 	  	Car Allowance or
Monetary  Value for
Personal Use of
Company Owned
Vehicle	 	  	Total	 	
Daniel P. Donovan	  	$	38,175	  	  	$	19,368	  	  	$	11,840	  	  	$	20,339	  	  	$	89,722	  	
Richard F. Ambury	  	 	29,903	  	  	 	15,862	  	  	 	—  	  	  	 	19,200	  	  	 	64,965	  	
Steven J. Goldman	  	 	19,087	  	  	 	15,777	  	  	 	—  	  	  	 	20,137	  	  	 	55,001	  	
Richard G. Oakley	  	 	5,090	  	  	 	15,247	  	  	 	—  	  	  	 	16,800	  	  	 	37,137	  	
 
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Grants of Plan-Based Awards

 	 	 	 	 	Estimated Future Payouts
Equity Incentive Plan Awards (1)	 	 	Estimated Future Payouts
Under Equity Incentive Plan	 	 	All Other
Stocks
Awards:
Number of
Shares of	 	 	All Other
Option
Awards:
Number of
Securities	 	 	Exercise or
Base price of
Option	 	 	Grant
Date Fair
Value of
Stock and	 	
Name	 	Grant Date
(1)	 	 	Threshold
($)	 	 	Target ($)
(2)	 	 	Maximum
($)	 	 	Threshold
(#)	 	 	Target
(#)	 	 	Maximum
(#)	 	 	Stock or
Units (#)	 	 	Underlying
Options (#)	 	 	Awards
($/Sh)	 	 	Option
Awards	 	
Daniel P. Donovan	 	 	7/21/09	  	 	 	—  	  	 	$	570,598	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	
Richard F. Ambury	 	 	7/21/09	  	 	 	—  	  	 	$	455,000	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	
Steven J. Goldman	 	 	7/21/09	  	 	 	—  	  	 	$	430,000	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	
Richard G. Oakley	 	 	7/21/09	  	 	 	—  	  	 	$	155,000	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	
 
(1)	On July 21, 2009, the Board of Directors authorized the continuance of the Partnership’s annual profit sharing plan, subject to its power to terminate the plan at any time. Profit sharing allocations are described under “Compensation Philosophy and Policies—Profit Sharing Allocations.”	
(2)	The Partnership’s annual profit sharing plan does not provide for thresholds or maximums; the amounts listed represent the actual awards to the named executive officers for fiscal 2011.	
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	  	  	$	858,783	  	  	$	—  	  	
Richard F. Ambury	  	Retirement Plan	  	 	13	  	  	$	173,795	  	  	$	—  	  	
 	  	Supplemental Employee

Retirement Plan	  	 	—  	  	  	$	33,261	  	  	$	—  	  	
Steven J. Goldman	  	Retirement Plan	  	 	—  	  	  	$	—  	  	  	$	—  	  	
Richard G. Oakley	  	Retirement Plan	  	 	19	  	  	$	267,491	  	  	$	—  	  	
The named executive officers have accumulated benefits in the tax-qualified Petro defined benefit pension plan that was frozen in 1997 or in the tax-qualified Meenan defined benefit pension plan that was frozen in 2002, subsequent to its combination with Petro. Mr. Ambury also participated in a tax-qualified supplemental employee retirement plan which, prior to being frozen in 1997, represented contributions to an employee plan to compensate for a reduction in certain benefits prior to 1997. Mr. Goldman was not a participant in any of these plans. Each year, the name executive officer’s accumulated benefits are actuarially calculated generally based on the credited years of service and each employee’s compensation at the time the plan was frozen. The present value of these amounts are the present value of a single life annuity generally payable at later or normal retirement age, adjusted for changes in discount rates and government mandated mortality tables. See note 12. Employee Benefit Plans, to the Partnership’s consolidated financial statements, for the material assumptions applied in quantifying the present value of the accumulated benefits of these frozen plans.
 
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Nonqualified Defined Contribution and Other Nonqualified Deferred Compensation Plans

 	  	Nonqualified Deferred Compensation	 	
 	  	Executive	 	  	Registrant	 	  	Aggregate	 	 	Aggregate	 	  	Aggregate	 	
 	  	Contributions	 	  	Contributions	 	  	Earnings	 	 	Withdrawals /	 	  	Balance at	 	
Name	  	in Last FY	 	  	in Last FY	 	  	in Last FY	 	 	Distributions	 	  	Last FYE	 	
Daniel P. Donovan (1)	  	$	—  	  	  	$	11,840	  	  	$	(197	) 	 	$	—  	  	  	$	11,643	  	
 
(1)	Mr. Donovan is a participant in the Partnership’s frozen defined benefit pension plan and in fiscal year 2011 reached the plan’s full retirement age. In April 2011, the Board of Directors approved a deferred compensation arrangement to be funded by amounts which would have been payable to Mr. Donovan had he retired at age 65 and until his actual retirement. Mr. Donovan may not make withdrawals from the fund and amounts due to him will be payable upon his actual retirement. Agreggate earnings and losses reflect normal market fluctuations from investments in the fund. Contributions to the fund are included in the Summary Compensation Table.	
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, 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.
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.
 
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Name	  	Potential Payments
Upon Termination	 	  	Potential  Payments
Following
a Change of Control	 	
Daniel P. Donovan (1)	  	$	413,100	  	  	$	1,993,265	  	
Richard F. Ambury (1)	  	$	331,500	  	  	$	1,586,333	  	
Steven J. Goldman	  	$	321,300	  	  	 	—  	  	
Richard G. Oakley	  	$	219,200	  	  	 	—  	  	
Compensation of Directors

 	  	Director Compensation Table	 	
Name	  	Fees
Earned
or Paid
in Cash	 	  	Unit
Awards	 	  	Option
Awards	 	  	Non-Equity
Incentive
Plan
Compensation	 	  	Change in
Pension
Value and
Nonqualified
Deferred
Compensation
Earnings (6)	 	  	All Other
Compensation	 	  	Total	 	
Paul A. Vermylen, Jr. (1)	  	$	126,000	  	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	$	76,137	  	  	 	—  	  	  	$	202,137	  	
Daniel P. Donovan (2)	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	 	—  	  	
Henry D. Babcock (3)	  	$	51,000	  	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	$	51,000	  	
C. Scott Baxter (3)	  	$	49,500	  	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	$	49,500	  	
Bryan H. Lawrence (4)	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	 	—  	  	
Sheldon B. Lubar	  	$	34,500	  	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	$	34,500	  	
William P. Nicoletti (5)	  	$	57,000	  	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	$	57,000	  	
 
(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 participates 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 ($37,500 beginning in fiscal year 2012) plus $1,500 for each regular and telephonic meeting attended. The Chairman of the Audit Committee receives an annual fee of $12,000 ($15,000 beginning in fiscal year 2012) while other Audit Committee members receive an annual fee of $6,000 ($7,500 beginning in fiscal year 2012). 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.
 
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ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT	
The following table shows the beneficial ownership as of November 30, 2011 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	  	  	 	19.84	% 	 	 	325,729	  	  	 	100.00	% 	
Paul A. Vermylen, Jr.	  	 	155,000	  	  	 	*	  	 	 	 	 	  	 	 	 	
Daniel P. Donovan	  	 	19,500	  	  	 	*	  	 	 	 	 	  	 	 	 	
Steven J. Goldman	  	 	5,000	  	  	 	 	 	 	 	 	 	  	 	 	 	
Richard F. Ambury	  	 	14,190	  	  	 	*	  	 	 	 	 	  	 	 	 	
Richard G. Oakley	  	 	—  	  	  	 	—  	  	 	 	 	 	  	 	 	 	
Henry D. Babcock	  	 	96,121	  	  	 	*	  	 	 	 	 	  	 	 	 	
C. Scott Baxter	  	 	75,000	  	  	 	*	  	 	 	 	 	  	 	 	 	
Bryan H. Lawrence	  	 	—  	  	  	 	—  	  	 	 	 	 	  	 	 	 	
Sheldon B. Lubar	  	 	200,000	  	  	 	*	  	 	 	 	 	  	 	 	 	
William P. Nicoletti	  	 	35,506	  	  	 	*	  	 	 	 	 	  	 	 	 	
 	 	 	 	 	
All officers and directors and Kestrel Heat, LLC as a group (11 persons)	  	 	13,403,445	  	  	 	20.77	% 	 	 	325,729	  	  	 	100.00	% 	
Bandera Partners LLC (b)	  	 	7,073,509	  	  	 	10.96	% 	 	 	 	 	  	 	 	 	
 
(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, LLC, a Delaware limited liability company (“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 August 12, 2011, 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.
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.
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.
 
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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, 2011, 2010 and 2009, 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 2011 and 2010, and for fees billed and accrued for other services rendered by KPMG LLP (in thousands).

 	  	2011	 	  	2010	 	
Audit Fees(1)	  	$	1,720	  	  	$	1,555	  	
Tax Fees(2)	  	 	453	  	  	 	426	  	
 	  	 	 	 	  	 	 	 	
Total Fees	  	$	2,173	  	  	$	1,981	  	

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(1) 	Audit fees were for professional services rendered in connection with audits and quarterly reviews of the consolidated financial statements of the Partnership. The fiscal 2011 amount includes $165,000 in audit fees, for services provided in fiscal 2010 but not paid until fiscal 2011, for the comfort letter provided in connection with the senior notes offering and audit services in connection with the Champion Acquisition.	
(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	  	4.3(16)	  	Amendment No. 2 to Second Amended and Restated Agreement of Limited Partnership	
 	 	 	
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(3)	  	Management Incentive Compensation Plan†	
 	 	 	
10.4	  	99.4(3)	  	Form of Indemnification Agreement for Officers and Directors.	
 	 	 	
10.5	  	(4)	  	Approved Dealer / Contractor Agreement dated as of July 11, 2006 by and between AFC First Financial Corporation and Petro Holdings, Inc.	
 	 	 	
10.6	  	99.4(7)	  	Form of Amendment No. 1 to Indemnification Agreement.	
 	 	 	
10.7	  	(9)	  	Description of 2008 Profit Sharing Plan.†	
 	 	 	
10.8	  	(10)	  	Employment Agreement dated December 3, 2007 between Star Gas Partners, L.P. and Steven J. Goldman.†	
 
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Exhibit
Number	  	Incorp by
Ref. to Exh.	  	Description	
  10.9	  	(10)	  	Change in Control Agreement dated December 4, 2007 between Star Gas Partners, L.P. and Daniel P. Donovan.†	
 	 	 	
  10.10	  	(10)	  	Change in Control Agreement dated December 4, 2007 between Star Gas Partners, L.P. and Richard F. Ambury.†	
 	 	 	
  10.11	  	(11)	  	Employment Agreement dated April 28, 2008 between Star Gas Partners, L.P. and Richard Ambury†	
 	 	 	
  10.12	  	(13)	  	Agreement dated November 2, 2009 between Star Gas Partners, L.P. and Richard G. Oakley.†	
 	 	 	
  10.13	  	(14)	  	Champion Equity Purchase Agreement dated as of May 10, 2010.	
 	 	 	
  10.14	  	(15)	  	Employment Agreement dated as of November 8, 2010 between Star Gas Partners, L.P. and Daniel P. Donovan.	
 	 	 	
  10.15	  	10.21(16)	  	Senior Notes Purchase Agreement, dated as of November 10, 2010, between Star Gas Partners, L.P., J.P. Morgan Securities LLC and RBS.	
 	 	 	
  10.16	  	10.22(16)	  	Senior Notes Registration Rights Agreement, dated as of November 16, 2010, between Star Gas Partners, L.P. and J.P. Morgan Securities LLC.	
 	 	 	
  10.17	  	10.23(16)	  	Indenture dated as of November 16, 2010 for the 8.875% Senior Notes due 2017.	
 	 	 	
  10.18	  	10.24(17)	  	Amended and Restated Revolving Credit Facility Agreement dated as of June 3, 2011.	
 	 	 	
  10.19	  	10.25(17)	  	Amended and Restated Pledge Agreement dated as of June 3, 2011.	
 	 	 	
  10.20	  	*	  	First Amendment dated as of November 22, 2011 to Amended and Restated Revolving Credit Facility Agreement.	
 	 	 	
  14   	  	(11)	  	Code of Business Conduct and Ethics	
 	 	 	
  21   	  	*	  	Subsidiaries of the Registrant	
 	 	 	
  23.1	  	*	  	Consent of KPMG	
 	 	 	
  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)	
 	 	 	
  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)	
 	 	 	
101.INS	  	(18)	  	XBRL Instance Document.	
 	 	 	
101.SCH	  	(18)	  	XBRL Taxonomy Extension Schema Document.	
 
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Exhibit
Number	  	Incorp by
Ref. to Exh.	  	Description	
101.CAL	  	(18)	  	XBRL Taxonomy Extension Calculation Linkbase Document.	
 	 	 	
101.LAB	  	(18)	  	XBRL Taxonomy Extension Label Linkbase Document.	
 	 	 	
101.PRE	  	(18)	  	XBRL Taxonomy Extension Presentation Linkbase Document.	
 	 	 	
101.DEF	  	(18)	  	XBRL Taxonomy Extension Definition Linkbase Document.	
 
*	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)	[Intentionally Omitted]	
(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 November 3, 2009.	
(14)	Incorporated by reference to an exhibit to the Registrant’s Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2010.	
(15)	Incorporated by reference to an exhibit to the Registrant’s Current Report on Form 8-K dated November 12, 2010.	
(16)	Incorporated by reference to an exhibit to the Registrant’s Annual Report on Form 10-K for the fiscal year ended September 30, 2010.	
(17)	Incorporated by reference to an exhibit to the Registrant’s Current Report on Form 8-K dated June 7, 2011.	
(18)	Filed herewith. In accordance with Rule 406T of Regulation S-T, these interactive data files are deemed “not filed” for purposes of section 18 of the Exchange Act, and otherwise are not subject to liability under that section.	
 
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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 7, 2011	
 	 	 	 	 	
/s/ Richard F. Ambury
Richard F. Ambury	  	 	  	Chief Financial Officer
(Principal Financial Officer)
Kestrel Heat, LLC	  	 	  	December 7, 2011	
 	 	 	 	 	
/s/ Richard G. Oakley
Richard G. Oakley	  	 	  	Vice President—Controller
(Principal Accounting Officer)
Kestrel Heat, LLC	  	 	  	December 7, 2011	
 	 	 	 	 	
/s/ Paul A. Vermylen, Jr.
Paul A. Vermylen, Jr.	  	 	  	Non-Executive Chairman of the Board
and Director Kestrel Heat, LLC	  	 	  	December 7, 2011	
 	 	 	 	 	
/s/ Henry D. Babcock
Henry D. Babcock	  	 	  	Director
Kestrel Heat, LLC	  	 	  	December 7, 2011	
 	 	 	 	 	
/s/ C. Scott Baxter
C. Scott Baxter	  	 	  	Director
Kestrel Heat, LLC	  	 	  	December 7, 2011	
 	 	 	 	 	
/s/ Bryan H. Lawrence
Bryan H. Lawrence	  	 	  	Director
Kestrel Heat, LLC	  	 	  	December 7, 2011	
 	 	 	 	 	
/s/ Sheldon B. Lubar
Sheldon B. Lubar	  	 	  	Director
Kestrel Heat, LLC	  	 	  	December 7, 2011	
 	 	 	 	 	
/s/ William P. Nicoletti
William P. Nicoletti	  	 	  	Director
Kestrel Heat, LLC	  	 	  	December 7, 2011	
 
63

Table of Contents
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, 2011 and September 30, 2010	  	F-3	
 	 	 	
 	 	Consolidated Statements of Operations for the years ended September 30, 2011,  September 30, 2010 and September 30, 2009	  	F-4	
 	 	 	
 	 	Consolidated Statements of Partners’ Capital and Comprehensive Income (Loss) for the years ended September 30, 2011, September 30, 2010 and September 30, 2009	  	F-5	
 	 	 	
 	 	Consolidated Statements of Cash Flows for the years ended September 30, 2011,  September 30, 2010 and September 30, 2009	  	F-6	
 	 	 	
 	 	Notes to Consolidated Financial Statements	  	F-7 – F-25	
 	 	 	
 	 	Schedules for the years ended September 30, 2011, September 30, 2010 and September 30, 2009	  	 	
 	 	 	
 	 	I. Condensed Financial Information of Registrant	  	F-26 – F-28	
 	 	 	
 	 	II. Valuation and Qualifying Accounts	  	F-29	
 	 	 	
 	 	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

Table of Contents
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, 2011 and 2010, 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, 2011. 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, 2011, 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, 2011 and 2010, and the results of its operations and its cash flows for each of the years in the three-year period ended September 30, 2011, 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, 2011, based on criteria established in  Internal Control – Integrated Framework  issued by the Committee of Sponsoring Organizations of the Treadway Commission.
KPMG LLP
Stamford, Connecticut
December 7, 2011
 
F-2

Table of Contents
STAR GAS PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS

 	  	Years Ended September 30,	 	
(in thousands)	  	2011	 	 	2010	 	
ASSETS	  	 	 	 	 	 	 	 	
Current assets	  	 	 	 	 	 	 	 	
Cash and cash equivalents	  	$	86,789	  	 	$	61,062	  	
Receivables, net of allowance of $9,530 and $5,443, respectively	  	 	92,967	  	 	 	70,443	  	
Inventories	  	 	80,536	  	 	 	66,734	  	
Fair asset value of derivative instruments	  	 	3,674	  	 	 	7,158	  	
Current deferred tax assets, net	  	 	13,155	  	 	 	20,247	  	
Prepaid expenses and other current assets	  	 	22,296	  	 	 	21,219	  	
 	  	 	 	 	 	 	 	 	
Total current assets	  	 	299,417	  	 	 	246,863	  	
 	  	 	 	 	 	 	 	 	
Property and equipment, net	  	 	47,131	  	 	 	44,712	  	
Goodwill	  	 	199,296	  	 	 	199,052	  	
Intangibles, net	  	 	52,348	  	 	 	58,894	  	
Long-term deferred tax assets, net	  	 	17,646	  	 	 	26,551	  	
Deferred charges and other assets, net	  	 	10,291	  	 	 	6,436	  	
 	  	 	 	 	 	 	 	 	
Total assets	  	$	626,129	  	 	$	582,508	  	
 	  	 	 	 	 	 	 	 	
LIABILITIES AND PARTNERS’ CAPITAL	  	 	 	 	 	 	 	 	
Current liabilities	  	 	 	 	 	 	 	 	
Accounts payable	  	$	18,569	  	 	$	16,626	  	
Fair liability value of derivative instruments	  	 	3,322	  	 	 	1,586	  	
Accrued expenses and other current liabilities	  	 	76,428	  	 	 	68,854	  	
Unearned service contract revenue	  	 	40,903	  	 	 	40,110	  	
Customer credit balances	  	 	67,214	  	 	 	68,762	  	
 	  	 	 	 	 	 	 	 	
Total current liabilities	  	 	206,436	  	 	 	195,938	  	
 	  	 	 	 	 	 	 	 	
Long-term debt	  	 	124,263	  	 	 	82,770	  	
Other long-term liabilities	  	 	22,797	  	 	 	23,889	  	
Partners’ capital	  	 	 	 	 	 	 	 	
Common unitholders	  	 	299,913	  	 	 	307,092	  	
General partner	  	 	187	  	 	 	290	  	
Accumulated other comprehensive loss, net of taxes	  	 	(27,467	) 	 	 	(27,471	) 	
 	  	 	 	 	 	 	 	 	
Total partners’ capital	  	 	272,633	  	 	 	279,911	  	
 	  	 	 	 	 	 	 	 	
Total liabilities and partners’ capital	  	$	626,129	  	 	$	582,508	  	
 	  	 	 	 	 	 	 	 	
See accompanying notes to consolidated financial statements.
 
F-3

Table of Contents
STAR GAS PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS

 	  	Years Ended September 30,	 	
(in thousands, except per unit data)	  	2011	 	 	2010	 	 	2009	 	
Sales:	  	 	 	 	 	 	 	 	 	 	 	 	
Product	  	$	1,392,871	  	 	$	1,028,423	  	 	$	1,032,812	  	
Installations and service	  	 	198,439	  	 	 	184,353	  	 	 	174,001	  	
 	  	 	 	 	 	 	 	 	 	 	 	 	
Total sales	  	 	1,591,310	  	 	 	1,212,776	  	 	 	1,206,813	  	
Cost and expenses:	  	 	 	 	 	 	 	 	 	 	 	 	
Cost of product	  	 	1,057,783	  	 	 	734,594	  	 	 	708,185	  	
Cost of installations and service	  	 	179,558	  	 	 	169,453	  	 	 	167,570	  	
(Increase) decrease in the fair value of derivative instruments	  	 	2,567	  	 	 	(5,622	) 	 	 	(13,690	) 	
Delivery and branch expenses	  	 	250,762	  	 	 	218,625	  	 	 	224,478	  	
Depreciation and amortization expenses	  	 	17,884	  	 	 	15,745	  	 	 	19,406	  	
General and administrative expenses	  	 	20,709	  	 	 	21,397	  	 	 	20,742	  	
 	  	 	 	 	 	 	 	 	 	 	 	 	
Operating income	  	 	62,047	  	 	 	58,584	  	 	 	80,122	  	
 	  	 	 	 	 	 	 	 	 	 	 	 	
Interest expense	  	 	(15,710	) 	 	 	(14,326	) 	 	 	(17,842	) 	
Interest income	  	 	4,870	  	 	 	3,506	  	 	 	4,205	  	
Amortization of debt issuance costs	  	 	(2,440	) 	 	 	(2,680	) 	 	 	(2,750	) 	
Gain (loss) on redemption of debt	  	 	(1,700	) 	 	 	(1,132	) 	 	 	9,706	  	
 	  	 	 	 	 	 	 	 	 	 	 	 	
Income before income taxes	  	 	47,067	  	 	 	43,952	  	 	 	73,441	  	
Income tax expense (benefit)	  	 	22,723	  	 	 	15,632	  	 	 	(57,597	) 	
 	  	 	 	 	 	 	 	 	 	 	 	 	
Net income	  	$	24,344	  	 	$	28,320	  	 	$	131,038	  	
 	  	 	 	 	 	 	 	 	 	 	 	 	
General Partner’s interest in net income	  	 	115	  	 	 	128	  	 	 	561	  	
 	  	 	 	 	 	 	 	 	 	 	 	 	
Limited Partners’ interest in net income	  	$	24,229	  	 	$	28,192	  	 	$	130,477	  	
 	  	 	 	 	 	 	 	 	 	 	 	 	
Basic and diluted income per Limited Partner Unit (1):	  	$	0.35	  	 	$	0.38	  	 	$	1.43	  	
 	  	 	 	 	 	 	 	 	 	 	 	 	
Weighted average number of Limited Partner units outstanding:	  	 	 	 	 	 	 	 	 	 	 	 	
Basic and Diluted	  	 	66,822	  	 	 	70,019	  	 	 	75,738	  	

 
(1)	See Note 17 Earnings Per Limited Partner Units.	
See accompanying notes to consolidated financial statements.
 
F-4

Table of Contents
STAR GAS PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL AND COMPREHENSIVE INCOME (LOSS)
Years Ended September 30, 2011, 2010 and 2009

 	  	Number of Units	 	  	 	 	 	 	 	 	 	 	 	 	 	
(in thousands)	  	Common	 	 	General
Partner	 	  	Common	 	 	General
Partner	 	 	Accum. Other
Comprehensive
Income (Loss)	 	 	Total
Partners’
Capital	 	
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 effect of unrealized loss on pension plan obligation	  	 	 	 	 	 	 	 	  	 	 	 	 	 	 	 	 	 	4,920	  	 	 	4,920	  	
 	  	 	 	 	 	 	 	 	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total comprehensive income	  	 	—  	  	 	 	—  	  	  	 	130,477	  	 	 	561	  	 	 	(6,934	) 	 	 	124,104	  	
Distributions (1)	  	 	 	 	 	 	 	 	  	 	(15,345	) 	 	 	(66	) 	 	 	 	 	 	 	(15,411	) 	
Retirement of units (2)	  	 	(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 effect of unrealized loss on pension plan obligation	  	 	 	 	 	 	 	 	  	 	 	 	 	 	 	 	 	 	821	  	 	 	821	  	
 	  	 	 	 	 	 	 	 	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total comprehensive income	  	 	—  	  	 	 	—  	  	  	 	28,192	  	 	 	128	  	 	 	(1,156	) 	 	 	27,164	  	
Distributions (1)	  	 	 	 	 	 	 	 	  	 	(20,206	) 	 	 	(147	) 	 	 	 	 	 	 	(20,353	) 	
Retirement of units (2)	  	 	(8,059	) 	 	 	 	 	  	 	(33,234	) 	 	 	 	 	 	 	 	 	 	 	(33,234	) 	
 	  	 	 	 	 	 	 	 	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Balance as of September 30, 2010	  	 	67,078	  	 	 	326	  	  	$	307,092	  	 	$	290	  	 	$	(27,471	) 	 	$	279,911	  	
Net income	  	 	 	 	 	 	 	 	  	 	24,229	  	 	 	115	  	 	 	 	 	 	 	24,344	  	
Unrealized gain on pension plan obligation	  	 	 	 	 	 	 	 	  	 	 	 	 	 	 	 	 	 	171	  	 	 	171	  	
Tax effect of unrealized gain on pension plan obligation	  	 	 	 	 	 	 	 	  	 	 	 	 	 	 	 	 	 	(167	) 	 	 	(167	) 	
 	  	 	 	 	 	 	 	 	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total comprehensive income	  	 	—  	  	 	 	—  	  	  	 	24,229	  	 	 	115	  	 	 	4	  	 	 	24,348	  	
Distributions (1)	  	 	 	 	 	 	 	 	  	 	(20,459	) 	 	 	(218	) 	 	 	 	 	 	 	(20,677	) 	
Retirement of units (2)	  	 	(2,108	) 	 	 	 	 	  	 	(10,949	) 	 	 	 	 	 	 	 	 	 	 	(10,949	) 	
 	  	 	 	 	 	 	 	 	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Balance as of September 30, 2011	  	 	64,970	  	 	 	326	  	  	$	299,913	  	 	$	187	  	 	$	(27,467	) 	 	$	272,633	  	

 
(1)	See Note 4—Quarterly Distributions of Available Cash.	
(2)	See Note 2—Common Unit Repurchase and Retirement.	
See accompanying notes to consolidated financial statements.
 
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Table of Contents
STAR GAS PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS

 	  	Years Ended September 30,	 	
(in thousands)	  	2011	 	 	2010	 	 	2009	 	
Cash flows provided by (used in) operating activities:	  	 	 	 	 	 	 	 	 	 	 	 	
Net income	  	$	24,344	  	 	$	28,320	  	 	$	131,038	  	
Adjustments to reconcile net income to net cash provided by (used in) operating activities:	  	 	 	 	 	 	 	 	 	 	 	 	
(Increase) decrease in fair value of derivative instruments	  	 	2,567	  	 	 	(5,622	) 	 	 	(13,690	) 	
Depreciation and amortization	  	 	20,324	  	 	 	18,425	  	 	 	22,157	  	
(Gain) loss on redemption of debt	  	 	1,700	  	 	 	1,132	  	 	 	(9,706	) 	
Provision for losses on accounts receivable	  	 	10,388	  	 	 	5,279	  	 	 	10,310	  	
Change in deferred taxes	  	 	15,831	  	 	 	13,331	  	 	 	(61,355	) 	
Changes in operating assets and liabilities net of amounts related to acquisitions:	  	 	 	 	 	 	 	 	 	 	 	 	
(Increase) decrease in receivables	  	 	(31,593	) 	 	 	(4,570	) 	 	 	26,657	  	
Increase in inventories	  	 	(13,189	) 	 	 	(2,012	) 	 	 	(17,747	) 	
Decrease in other assets	  	 	1,594	  	 	 	13,912	  	 	 	4,230	  	
Increase (decrease) in accounts payable	  	 	1,943	  	 	 	(1,784	) 	 	 	216	  	
Decrease in customer credit balances	  	 	(1,776	) 	 	 	(9,250	) 	 	 	(11,964	) 	
Increase (decrease) in other current and long-term liabilities	  	 	7,269	  	 	 	(12,732	) 	 	 	(1,691	) 	
 	  	 	 	 	 	 	 	 	 	 	 	 	
Net cash provided by operating activities	  	 	39,402	  	 	 	44,429	  	 	 	78,455	  	
 	  	 	 	 	 	 	 	 	 	 	 	 	
Cash flows provided by (used in) investing activities:	  	 	 	 	 	 	 	 	 	 	 	 	
Capital expenditures	  	 	(6,361	) 	 	 	(5,567	) 	 	 	(4,334	) 	
Proceeds from sales of fixed assets	  	 	92	  	 	 	392	  	 	 	159	  	
Acquisitions (net of cash acquired of $0, $3,390, and $0, respectively)	  	 	(9,659	) 	 	 	(68,658	) 	 	 	(3,393	) 	
Earnout	  	 	—  	  	 	 	(123	) 	 	 	—  	  	
 	  	 	 	 	 	 	 	 	 	 	 	 	
Net cash used in investing activities	  	 	(15,928	) 	 	 	(73,956	) 	 	 	(7,568	) 	
 	  	 	 	 	 	 	 	 	 	 	 	 	
Cash flows provided by (used in) financing activities:	  	 	 	 	 	 	 	 	 	 	 	 	
Revolving credit facility borrowings	  	 	88,416	  	 	 	36,754	  	 	 	—  	  	
Revolving credit facility repayments	  	 	(88,416	) 	 	 	(36,754	) 	 	 	—  	  	
Repayment of debt	  	 	(82,499	) 	 	 	(50,854	) 	 	 	(30,230	) 	
Proceeds from the issuance of debt	  	 	124,188	  	 	 	—  	  	 	 	—  	  	
Debt extinguishment costs	  	 	(1,409	) 	 	 	—  	  	 	 	—  	  	
Distributions	  	 	(20,677	) 	 	 	(20,353	) 	 	 	(15,411	) 	
Unit repurchase	  	 	(10,949	) 	 	 	(33,234	) 	 	 	(2,336	) 	
Increase in deferred charges	  	 	(6,401	) 	 	 	(130	) 	 	 	(6,558	) 	
 	  	 	 	 	 	 	 	 	 	 	 	 	
Net cash provided by (used in) financing activities	  	 	2,253	  	 	 	(104,571	) 	 	 	(54,535	) 	
 	  	 	 	 	 	 	 	 	 	 	 	 	
Net increase (decrease) in cash	  	 	25,727	  	 	 	(134,098	) 	 	 	16,352	  	
Cash and equivalent at beginning of period	  	 	61,062	  	 	 	195,160	  	 	 	178,808	  	
 	  	 	 	 	 	 	 	 	 	 	 	 	
Cash and equivalent at end of period	  	$	86,789	  	 	$	61,062	  	 	$	195,160	  	
 	  	 	 	 	 	 	 	 	 	 	 	 	
See accompanying notes to consolidated financial statements.
 
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Table of Contents
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 and propane distributor and services provider with one reportable operating segment that principally provides services to residential and commercial customers to heat their homes and buildings. Star Gas Partners is a master limited partnership, which at September 30, 2011, had outstanding 65.0 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 subject to Federal and state corporation income taxes. Petro is a Northeast and Mid-Atlantic region retail distributor of home heating oil and propane that at September 30, 2011 served approximately 407,000 full-service residential and commercial home heating oil and propane customers. Petro also sold home heating oil, gasoline and diesel fuel to approximately 39,000 customers on a delivery only basis. In addition, Petro installed, maintained, and repaired heating and air conditioning equipment for its customers, and provided ancillary home services, including home security and plumbing, to approximately 11,000 customers.	
 
 	•	 	Star Gas Finance Company is a 100% owned subsidiary of the Partnership. Star Gas Finance Company serves as the co-issuer, jointly and severally with the Partnership, of its $125 million (excluding discount) 8.875% Senior Notes outstanding at September 30, 2011, that is due 2017. The Partnership is dependent on distributions including inter-company interest payments from its subsidiaries to service the Partnership’s debt obligations. The distributions from the Partnership’s subsidiaries are not guaranteed and are subject to certain loan restrictions. Star Gas Finance Company has nominal assets and conducts no business operations. (See Note 10—Long-Term Debt and Bank Facility Borrowings)	
2) 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 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. As of September 30, 2011, 2.1 million common units authorized for repurchase under Plan II were repurchased at an average price paid per unit of $5.19.
 
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(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 (b)	 	  	Maximum Number of Units
that May Yet Be Purchased
Under the Plan II Program	 	
Plan II - Number of units authorized	  	 	 	 	 	 	 	 	  	 	7,000	  	
 	  	 	 	 	 	 	 	 	  	 	 	 	
Plan II - Fiscal year 2010 total (a)	  	 	1,197	  	 	$	4.44	  	  	 	5,803	  	
 	  	 	 	 	 	 	 	 	  	 	 	 	
Plan II - Fiscal year 2011 first quarter	  	 	—  	  	 	$	—  	  	  	 	5,803	  	
 	  	 	 	 	 	 	 	 	  	 	 	 	
Plan II - Fiscal year 2011 second quarter	  	 	—  	  	 	$	—  	  	  	 	5,803	  	
 	  	 	 	 	 	 	 	 	  	 	 	 	
Plan II - Fiscal year 2011 third quarter	  	 	—  	  	 	$	—  	  	  	 	5,803	  	
 	  	 	 	 	 	 	 	 	  	 	 	 	
Plan II - July 2011	  	 	—  	  	 	$	—  	  	  	 	5,803	  	
Plan II - August 2011	  	 	1,835	(c) 	 	$	5.22	  	  	 	3,968	  	
Plan II - September 2011	  	 	273	  	 	$	5.03	  	  	 	3,695	  	
 	  	 	 	 	 	 	 	 	  	 	 	 	
Plan II - Fiscal year 2011 fourth quarter total	  	 	2,108	  	 	$	5.19	  	  	 	3,695	  	
 	  	 	 	 	 	 	 	 	  	 	 	 	
Plan II - Fiscal year 2011 total	  	 	2,108	  	 	$	5.19	  	  	 	3,695	  	

(a)	In fiscal year 2010 we also repurchased 6.9 million common units, concluding repurchase Plan I.	
(b)	Amounts include repurchase costs.	
(c)	August 2011 common unit repurchase include 1.5 million common units acquired in a private sale.	
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.
Use of Estimates
The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates.
Revenue Recognition
Sales of heating oil and other fuels are recognized at the time of delivery of the product to the customer and sales of heating and air conditioning equipment are recognized at the time of installation. Revenue from repairs and maintenance service is recognized upon completion of the service. Payments received from customers for 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.
 
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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, garage mechanics, customer service, sales and marketing, compliance, credit and branch accounting, information technology, insurance and operational support.
General and Administrative Expenses
General and administrative expenses include wages and benefits and department related costs for human resources, finance and partnership accounting, administrative support and supply.
Allowance for Doubtful Accounts
The allowance for doubtful accounts, which includes the allowance for long-term receivables, is the Partnership’s best estimate of the amount of trade receivables that may not be collectible. The allowance is determined at an aggregate level (as opposed to account by account) by grouping accounts based on the type of account and its receivable aging. The allowance is based on both quantitative and qualitative factors, including historical loss experience, historical collection patterns, overdue status, aging trends, and current economic conditions. The Partnership has an established process to periodically review current and past due trade receivable balances to determine the adequacy of the allowance. No single statistic or measurement determines the adequacy of the allowance. The total allowance reflects management’s estimate of losses inherent in its trade receivables at the balance sheet date. Different assumptions or changes in economic conditions could result in material changes to the allowance for doubtful accounts.
Allocation of Net Income
Net income 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 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 03-06), by dividing the limited partners’ interest in net income by the weighted average number of limited partner units outstanding. The pro forma nature of the allocation required by this standard provides that in any accounting period where the Partnership’s aggregate net income exceeds its aggregate distribution for such period, the Partnership is required to present net income per limited partner unit as if all of the earnings for the periods were distributed, regardless of whether those earnings would actually be distributed during a particular period from an economic or practical perspective. This allocation does not impact the Partnership’s overall net income or other financial results. However, for periods in which the Partnership’s aggregate net income exceeds its aggregate distributions for such period, it will have the impact of reducing the earnings per limited partner unit, as the calculation according to this standard results in a theoretical increased allocation of undistributed earnings to the general partner. In accounting periods where aggregate net income does not exceed aggregate distributions for such period, this standard does not have any impact on the Partnership’s net income per limited partner unit calculation. A separate and independent calculation for each quarter and year-to-date period is performed, in which the Partnership’s contractual participation rights are taken into account.
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
Liquid product inventories 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.
 
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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 with FASB ASC 805 Business Combinations. The acquisition method of accounting requires the Partnership to use significant estimates and assumptions, including fair value estimates, as of the business combination date, and to refine those estimates as necessary during the measurement period (defined as the period, not to exceed one year, in which the amounts recognized for a business combination may be adjusted). Each acquired company’s operating results are included in the Partnership’s consolidated financial statements starting on the date of acquisition. The purchase price is equivalent to the fair value of consideration transferred. Tangible and identifiable intangible assets acquired and liabilities assumed as of the date of acquisition, are recorded at the acquisition date fair value. The separately identifiable intangible assets generally are comprised of customer lists, trade names and covenants not to compete. Goodwill is recognized for the excess of the purchase price over the net fair value of assets acquired and liabilities assumed.
Costs that are incurred to complete the business combination such as investment banking, legal and other professional fees are not considered part of consideration transferred, and are charged to general and administrative expense as they are incurred. For any given acquisition, certain contingent consideration may be identified. Estimates of the fair value of liability or asset classified contingent consideration are included under the acquisition method as part of the assets acquired or liabilities assumed. At each reporting date, these estimates are remeasured to fair value, with changes recognized in earnings.
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 $9.5 million, $9.6 million, and $8.4 million, in 2011, 2010, and 2009, 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 liquid product and other services.
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 uses a combination of insurance, self-insured retention and self-insurance for a number of risks, including workers’
 
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compensation, general liability, vehicle liability and property. Reserves are established and periodically evaluated, based upon expectations as to what our ultimate liability may be for outstanding claims using developmental factors based upon historical claim experience, including frequency, severity, demographic factors and other actuarial assumptions, supplemented with support from qualified actuaries.
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 (the Partnership’s corporate subsidiaries are subject to tax at the entity level for federal and state income tax purposes). While the Partnership will generate non-qualifying Master Limited Partnership revenue through its corporate subsidiaries, distributions from the corporate subsidiaries to the Partnership are generally included in the determination of qualified Master Limited Partnership income. All or a portion of the distributions received by the Partnership from the corporate subsidiaries could be 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.
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. 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 May 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2011-04, Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. generally accepted accounting principles (“U.S. GAAP”) and the International Financial Reporting Standards (“IFRS”), that results in a consistent definition of fair value and common requirements for measurement of and disclosure about fair value. The new guidance clarifies and changes some fair value measurement principles and disclosure requirements under U.S. GAAP. Among them is the clarification that the concepts of highest and best use and valuation premise in a fair value measurement, should only be applied when measuring the fair value of nonfinancial assets. Additionally, the new guidance requires quantitative information about unobservable inputs, disclosure of the valuation processes used and narrative descriptions with regard to fair value measurements within the Level 3 categorization of the fair value hierarchy. The new guidance is effective for interim and annual reporting periods beginning after December 15, 2011, with early adoption prohibited. The adoption of this new guidance is not expected to have a material impact on the Partnership’s Consolidated Financial Statements.
In June 2011, the FASB issued ASU No. 2011-05, Comprehensive Income (Topic 220): Presentation of Comprehensive Income, and subsequently issued a proposal to defer the requirement to separately present within net income reclassification adjustments of items out of accumulated other comprehensive income. This standard eliminates the option to present items of other comprehensive income (“OCI”) as part of the statement of changes in stockholders’ equity, and instead requires either OCI presentation and net income in a single continuous statement to the statement of operations, or as a separate statement of comprehensive income. ASU No. 2011-05 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011, with early adoption permitted. The Partnership is required to adopt this update in the first quarter of fiscal year 2013. The adoption of ASU No. 2011-05 will not impact our results of operations or the amount of assets and liabilities reported.
 
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In September 2011, the FASB issued ASU No. 2011-08, Intangibles-Goodwill and Other (Topic 350): Testing Goodwill for Impairment. This standard simplifies how entities test goodwill for impairment by providing for an optional qualitative assessment in determining whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount, as a basis for determining whether it is necessary to perform the first step, of the two-step goodwill impairment test. The new guidance is effective for annual and interim goodwill impairment tests performed in fiscal years beginning after December 15, 2011, with early adoption permitted. The Partnership has not early adopted this standard and is required to adopt this update in fiscal year 2012. The adoption of ASU No. 2011-08 will not impact our results of operations or the amount of assets and liabilities reported.
In September 2011, the FASB issued ASU No. 2011-09, Compensation—Retirement Benefits—Multiemployer Plans (Subtopic 715-80): Disclosures about an Employer’s Participation in a Multiemployer Plan. This standard requires employers that participate in multiemployer pension plans to provide additional quantitative and qualitative disclosures such as significant multiemployer plan names, identifying number, employer contributions, an indication of the plan’s funded status, and the nature of the employer commitments to the plan. The new guidance is effective for annual periods for fiscal years ending after December 15, 2011, with early adoption permitted. The Partnership has not early adopted this standard and is required to adopt it in fiscal year 2012. The adoption of ASU No. 2011-09 will not impact our results of operations or the amount of assets and liabilities reported.
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 Partnership is obligated to meet certain financial covenants under the amended and restated revolving credit facility. The Partnership must maintain excess availability of at least 17.5% of the revolving commitment then in effect and a fixed charge coverage ratio of 1.15 in order to make any distributions to unitholders.
For fiscal 2011, 2010 and 2009, cash distributions declared per common unit were $0.305, $0.285 and $0.2025, respectively.
For fiscal 2011, 2010 and 2009, $0.1 million, $0.1 million and $0, respectively, in incentive distributions were paid to the general partner, exclusive of amounts paid subject to the Management Incentive Plan.
 
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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, 2011 the Partnership had bought 3.1 million gallons of physical inventory and held 2.3 million gallons of swap contracts to buy heating oil with a notional value of $6.0 million and a fair value of $0.3 million, 5.5 million gallons of call options with a notional value of $16.3 million and a fair value of $1.2 million, 1.7 million gallons of put options with a notional value of $3.6 million and a fair value of $0.09 million and 80.0 million net gallons of synthetic calls with a notional value of $248.7 million and a fair value of $(5.0) 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, 2011 had 2.7 million gallons of future contracts to buy heating oil with a notional value of $7.9 million and a fair value of $(0.6) million, 4.2 million gallons of future contracts to sell heating oil with a notional value of $12.0 million and a fair value of $0.7 million and 20.7 million gallons of swap contracts to sell heating oil with a notional value of $62.2 million and a fair value of $4.6 million. To hedge a portion of its internal fuel usage, the Partnership as of September 30, 2011, had 1.6 million gallons of swap contracts to buy gasoline with a notional value of $4.5 million and a fair value of $(0.4) million and 1.5 million gallons of swap contracts to buy diesel with a notional value of $4.5 million and a fair value of $(0.4) 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, 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.
The Partnership’s derivative instruments are with the following counterparties: Key Bank National Association, JPMorgan Chase Bank, N.A., Bank of America, N.A., Cargill, Inc., Societe Generale and Newedge USA, LLC. 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. The Partnership periodically assesses counterparty credit risks and adjusts its positions accordingly; the Partnership has taken into account that several of our counterparties have possible exposure to sovereign debt risks. At September 30, 2011, the aggregate cash posted as collateral in the normal course of business at counterparties was $0.3 million. Positions with counterparties who are also parties to our revolving credit facility are collateralized under that facility. As of September 30, 2011, $7.8 million of hedging losses were secured under the revolving credit facility.
FASB ASC 815-10-05, Derivatives and Hedging topic, established accounting and reporting standards requiring that derivative instruments be recorded at fair value and included in the consolidated balance sheet as assets or liabilities, along with qualitative disclosures regarding the derivative activity. 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. Depending on the risk being hedged, realized gains and losses are recorded in cost of product, cost of installations and service, or delivery and branch expenses.
FASB ASC 820-10, Fair Value Measurements and Disclosures topic, established a three-tier fair value hierarchy, which classified the inputs used in measuring fair value. These tiers include: Level 1, defined as observable inputs such as quoted prices for identical instruments in active markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions. The Partnership’s Level 1 derivative assets and liabilities represent the fair value of commodity contracts used in its hedging activities that are identical and traded in active markets. The Partnership’s Level 2 derivative assets and liabilities represent the fair value of commodity contracts used in its hedging activities that are valued using either directly or indirectly observable inputs, whose nature, risk and class are similar. No significant transfers of assets or liabilities have been made into and out of the Level 1 or Level 2 tiers. All derivative instruments were non-trading positions. The market prices used to value the Partnership’s derivatives have been determined using the New York Mercantile Exchange (“NYMEX”) and independent third party prices that are reviewed for reasonableness.
The Partnership had no assets or liabilities that are measured at fair value on a nonrecurring basis subsequent to their initial recognition. The Partnership’s financial assets and liabilities measured at fair value on a recurring basis are listed on the following table.
 
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(In thousands)	 	  	 	 	 	 	Fair Value Measurements at Reporting Date Using:	 	
Derivatives Not Designated as Hedging	 	 	 	 	 	 	Quoted Prices in
Active Markets for
Identical Assets	 	 	Significant Other
Observable Inputs	 	 	Significant
Unobservable
Inputs	 	
Instruments Under FASB ASC 815-10	 	Balance Sheet Location	 	Total	 	 	Level 1	 	 	Level 2	 	 	Level 3	 	
Asset Derivatives at September 30, 2011	 	
Commodity contracts	 	Fair asset and fair liability value of derivative instruments	 	$	41,531	  	 	$	550	  	 	$	40,981	  	 	$	—  	  	
Commodity contracts	 	Long-term derivative assets included in the deferred charges and other assets, net balance	 	 	257	  	 	 	171	  	 	 	86	  	 	 	—  	  	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Commodity contract assets at September 30, 2011	 	$	41,788	  	 	$	721	  	 	$	41,067	  	 	$	—  	  	

Liability Derivatives at September 30, 2011	 	
Commodity contracts	 	Fair liability and fair asset value of derivative instruments	 	$	(41,179	) 	 	$	(602	) 	 	$	(40,577	) 	 	$	—  	  	
Commodity contracts	 	Long-term derivative liabilities netted with the deferred charges and other assets, net balance	 	 	(96	) 	 	 	(25	) 	 	 	(71	) 	 	 	—  	  	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Commodity contract liabilities at September 30, 2011	 	$	(41,275	) 	 	$	(627	) 	 	$	(40,648	) 	 	$	—  	  	

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	) 	 	$	—  	  	

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(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, 2011	 	 	Twelve Months  Ended
September 30, 2010	 	 	Twelve Months  Ended
September 30, 2009	 	
Commodity contracts	  	Cost of product (a)	  	$	(9,089	) 	 	$	24,412	  	 	$	73,574	  	
Commodity contracts	  	Cost of installations and service (a)	  	$	(1,030	) 	 	$	(958	) 	 	$	3,012	  	
Commodity contracts	  	Delivery and branch expenses (a)	  	$	(740	) 	 	$	(512	) 	 	$	3,260	  	
Commodity contracts	  	(Increase) / decrease in the fair value of derivative instruments	  	$	2,567	  	 	$	(5,622	) 	 	$	(13,690	) 	
 
(a)	Represents realized closed positions and includes the cost of options as they expire.	
6) Inventories
The Partnership’s liquid product inventories are stated at the lower of cost or market computed on the weighted average cost method. All other inventories, representing parts and equipment are stated at the lower of cost or market using the FIFO method. The components of inventory were as follows:

 	  	September 30,	 	
(in thousands)	  	2011	 	  	2010	 	
Liquid product	  	$	64,907	  	  	$	51,678	  	
Parts and equipment	  	 	15,629	  	  	 	15,056	  	
 	  	 	 	 	  	 	 	 	
 	  	$	80,536	  	  	$	66,734	  	
 	  	 	 	 	  	 	 	 	
Heating oil and other fuel inventories were comprised of 20.8 million gallons and 24.0 million gallons on September 30, 2011 and September 30, 2010, respectively. The Partnership has market price based product supply contracts for approximately 209 million home heating oil gallons, that it expects to fully utilize to meet its requirements over the next twelve months.
During fiscal 2011, Global Companies, NIC Holding Corp. (Northville Industries) and Sunoco Inc. provided 21.6%, 12.6% and 10.9% respectively, of our product purchases. Aside from these three suppliers, no single supplier provided more than 10% of our product supply during fiscal 2011.
7) Property and Equipment
The components of property and equipment and their estimated useful lives were as follows (in thousands):

 	  	September 30,	 	  	 	
 	  	2011	 	  	2010	 	  	Useful Estimated Lives	
Land and land improvements	  	$	13,769	  	  	$	13,445	  	  	Land improvements -30 years	
Buildings and leasehold improvements	  	 	26,198	  	  	 	25,608	  	  	1 - 30 years	
Fleet and other equipment	  	 	43,541	  	  	 	41,454	  	  	1 - 25 years	
Tanks and equipment	  	 	14,166	  	  	 	11,117	  	  	20 years	
Furniture, fixtures and office equipment	  	 	57,752	  	  	 	54,870	  	  	3 -10 years	
 	  	 	 	 	  	 	 	 	  	 	
Total	  	 	155,426	  	  	 	146,494	  	  	 	
Less accumulated depreciation	  	 	108,295	  	  	 	101,782	  	  	 	
 	  	 	 	 	  	 	 	 	  	 	
Property and equipment, net	  	$	47,131	  	  	$	44,712	  	  	 	
 	  	 	 	 	  	 	 	 	  	 	
Depreciation expense was $7.3 million, $6.0 million, and $6.2 million, for the fiscal years ended September 30, 2011, 2010, and 2009 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, 2011, 2010, and 2009, 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, 2011 and 2010 are as follows (in thousands):

Balance as of September 30, 2009	  	$	182,942	  	
Fiscal year 2010 acquisitions	  	 	16,110	  	
 	  	 	 	 	
Balance as of September 30, 2010	  	 	199,052	  	
Fiscal year 2011 acquisitions (see Note 11. Business Combinations)	  	 	244	  	
 	  	 	 	 	
Balance as of September 30, 2011	  	$	199,296	  	
 	  	 	 	 	
Intangibles, net
Intangible assets subject to amortization consist of the following (in thousands):

 	  	September 30, 2011	 	  	September 30, 2010	 	
 	  	Gross
Carrying
Amount	 	  	Accum.
Amortization	 	  	Net	 	  	Gross
Carrying
Amount	 	  	Accum.
Amortization	 	  	Net	 	
Customer lists and other intangibles	  	$	256,172	  	  	$	203,824	  	  	$	52,348	  	  	$	252,385	  	  	$	193,491	  	  	$	58,894	  	
 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Amortization expense for intangible assets was $10.3 million, $9.5 million, and $13.0 million, for the fiscal years ended September 30, 2011, 2010, and 2009, respectively. Total estimated annual amortization expense related to intangible assets subject to amortization, for the year ended September 30, 2012 and the four succeeding fiscal years ended September 30, is as follows (in thousands):

 	  	Amount	 	
2012	  	$	6,225	  	
2013	  	$	6,223	  	
2014	  	$	6,147	  	
2015	  	$	6,011	  	
2016	  	$	5,841	  	
 
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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,	 	
 	  	2011	 	  	2010	 	
Accrued wages and benefits	  	$	17,638	  	  	$	16,135	  	
Accrued workers’ compensation, general liability, auto claims and environmental	  	 	47,325	  	  	 	42,466	  	
Other accrued expenses and other current liabilities	  	 	11,465	  	  	 	10,253	  	
 	  	 	 	 	  	 	 	 	
 	  	$	76,428	  	  	$	68,854	  	
 	  	 	 	 	  	 	 	 	
10) Long-Term Debt and Bank Facility Borrowings
The Partnership’s debt is as follows (in thousands):

 	  	At September 30, 2011	 	  	At September 30, 2010	 	
 	  	Carrying
Amount	 	  	Estimated
Fair Value  (a)	 	  	Carrying
Amount	 	  	Estimated
Fair Value  (a)	 	
8.875% Senior Notes (b)	  	$	124,263	  	  	$	127,500	  	  	$	—  	  	  	$	—  	  	
10.25% Senior Notes (c)	  	 	—  	  	  	 	—  	  	  	 	82,770	  	  	 	83,908	  	
Revolving Credit Facility Borrowings (d)	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	 	—  	  	
 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total debt	  	$	124,263	  	  	$	127,500	  	  	$	82,770	  	  	$	83,908	  	
 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total long-term portion of debt	  	$	124,263	  	  	$	127,500	  	  	$	82,770	  	  	$	83,908	  	

(a)	        The Partnership’s fair value estimates of long-term debt are made at a specific point in time, based on relevant market information, open market quotations and information about the financial instrument. These estimates are subjective in nature and involve uncertainties and matters of significant judgment. Changes in assumptions could significantly affect the estimates.	
 
(b)	        The Partnership issued $125.0 million (excluding discount) 8.875% Senior Notes in November 2010 in a private placement offering pursuant to Rule 144A and Regulation S under the Securities Act of 1933, as amended (the “Private Notes”). In February 2011, the Partnership concluded an exchange of all the Private Notes for substantially identical public notes registered with the Securities and Exchange Commission (the “Exchange Notes”). These notes mature in December 2017 and accrue interest at an annual rate of 8.875% requiring semi-annual interest payments on June 1 and December 1 of each year. The discount on these notes was $0.7 million at September 30, 2011. Under the terms of the indenture, these notes permit restricted payments after passing certain financial tests. The Partnership can incur debt up to $100 million for acquisitions and can also pay restricted payments of $22.0 million without passing certain financial tests.	
 
(c)	        In December 2010, the Partnership redeemed its 10.25% Senior Notes due February 2013, at a price equal to 101.708% of face value plus any accrued and unpaid interest. In fiscal year 2011 the Partnership reported a $1.7 million loss on this redemption.	
 
(d)	        In June 2011, the Partnership entered into an amended and restated asset based revolving credit facility agreement with a bank syndication comprised of fifteen banks. The amended and restated revolving credit facility expires in June 2016. Under this agreement, the Partnership may borrow up to $250 million ($300 million during the heating season from December to April each year) for working capital purposes (subject to certain borrowing base limitations and coverage ratios) and may issue up to $100 million in letters of credit. The Partnership can increase the facility size by $100 million without the consent of the bank group. The bank group is not obligated to fund the $100 million increase. If the bank group elects not to fund the increase, the Partnership can add additional lenders to the group, with the consent of the agent (as appointed in the revolving credit facility agreement), which shall not be unreasonably withheld.	
In November 2011, the Partnership exercised the provision under this agreement to expand the facility by an additional $50 million, thus providing total liquidity of $350 million for the fiscal 2012 heating season from December 2011 to April 2012 (See Note 19. Subsequent Events).
Obligations under the revolving credit facility are guaranteed by the Partnership and its subsidiaries and are secured by liens on substantially all of the Partnership’s assets including accounts receivable, inventory, general intangibles, real property, fixtures and equipment.
The interest rate is LIBOR plus (i) 1.75% (if availability, as defined in the revolving credit facility agreement is greater than or equal to $150 million), or (ii) 2.00% (if availability is greater than $75 million but less than $150 million), or (iii) 2.25% (if availability is less than or equal to $75 million). The commitment fee on the unused portion of the facility is 0.375% per annum. This amended and restated revolving credit facility imposes certain restrictions, including restrictions on the Partnership’s ability to incur additional indebtedness, to pay distributions to unitholders, to pay inter-company dividends or distributions, make investments, grant liens, sell assets, make acquisitions and engage in certain other activities.
 
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The Partnership is obligated to meet certain financial covenants under the amended and restated revolving credit facility, including the requirement to maintain at all times either availability (borrowing base less amounts borrowed and letters of credit issued) of $37.5 million, 12.5% of the maximum facility size at September 30, 2011, ($43.8 million at November 30, 2011) or a fixed charge coverage ratio (as defined in the revolving credit facility agreement) of not less than 1.1, which is calculated based upon Adjusted EBITDA. In order to make acquisitions, the Partnership must maintain availability of $40 million on a historical pro forma and forward-looking basis. In addition, the Partnership must maintain availability of $52.5 million, 17.5% of the maximum facility size at September 30, 2011, ($61.3 million at November 30, 2011) and a fixed charge coverage ratio of not less than 1.15 in order to make any distributions to unitholders. Certain activities including investments, acquisitions, asset sales, inter-company dividends or distributions cannot be made (including those needed to pay interest or principal on the 8.875% senior notes), except to the Partnership or a wholly owned subsidiary of the Partnership, if the relevant covenant described above has not been met. The occurrence of an event of default or an acceleration under the amended and restated revolving credit facility would result in the Partnership’s inability to obtain further borrowings under that facility, which could adversely affect its results of operations. Such a default may also restrict the ability of the Partnership to obtain funds from its subsidiaries in order to pay interest or paydown debt. An acceleration under the amended and restated revolving credit facility would result in a default under the Partnership’s other funded debt.
At September 30, 2011, no amount was outstanding under the revolving credit facility and $46.7 million of letters of credit were issued. At September 30, 2010, no amount was outstanding under the revolving credit facility and $42.3 million of letters of credit were issued.
As of September 30, 2011, availability was $162.4 million, the restricted net assets totaled approximately $390 million and the Partnership was in compliance with the fixed charge coverage ratio. Restricted net assets are assets in the Partnership’s subsidiaries the distribution or transfer of which to Star Gas Partners, L.P. are subject to limitations under its revolving credit facility. 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.
In July 2011, the Partnership’s shelf registration became effective, providing for the sale of up to $250 million in one or more offerings of common units representing limited partnership interests, partnership securities and debt securities; which may be secured or unsecured senior debt securities or secured or unsecured subordinated debt securities. As of September 30, 2011, no offerings under this shelf registration have occurred.
As of September 30, 2011, the maturities including working capital borrowings during fiscal years ending September 30, are set forth in the following table (in thousands):

2012	  	$	—  	 	
2013	  	$	—  	  	
2014	  	$	—  	  	
2015	  	$	—  	  	
2016	  	$	—  	  	
Thereafter	  	$	125,000	 	
11) Business Combinations
During fiscal 2011, the Partnership acquired four retail heating oil and propane dealers. The aggregate purchase price was approximately $9.7 million, including working capital of $1.9 million. The operating results of these four acquisitions have been included in the Partnership’s consolidated financial statements since the date of acquisition, and are not material to the Partnership’s financial condition, results of operations, or cash flows. Preliminary fair values of the assets acquired and liabilities assumed are comprised primarily of intangibles and certain working capital items, which are reflected in the Consolidated Balance Sheet as of September 30, 2011 and are pending final valuation within the permitted measurement period.
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.
 
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12) Employee Benefit Plans
Defined Contribution Plans
The Partnership has two 401(k) plans that cover eligible non-union and union employees. Subject to IRS limitations, the 401(k) plans provide for each participant to contribute from 0% to 60% of compensation. For most participants, the Partnership generally can make 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 generally can match 2/3 of each amount a participant contributes up to a maximum of 2.0% of a participant’s compensation. However, participants at specific operating locations that participate in these plans are only eligible for an employer discretionary pretax matching contribution and/or an annual employer discretionary profit sharing contribution. The Partnership’s aggregate contributions to the 401(k) plans during fiscal 2011, 2010, and 2009 were $4.7 million, $4.4 million, and $4.2 million, respectively.
Management Incentive Compensation Plan
The Partnership has a 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. 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 2011 Compensation Decisions—Management Incentive Compensation Plan.” The amount paid in Incentive Distributions is governed by the Partnership Agreement and the calculation of Available Cash.
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 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 $261,000 during fiscal 2011 and $116,000 during fiscal 2010 in Incentive Distributions, of which named executive officers received approximately $92,000 during fiscal 2011 and $40,000 during fiscal 2010 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.
Union-Administered Pension Plans
The Partnership’s contributions to union-administered pension plans were $7.0 million for fiscal 2011, $7.7 million for fiscal 2010, and $7.2 million for fiscal 2009. 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.
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:
 
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(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 2009	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Beginning balance	  	 	 	 	 	 	 	 	 	$	38,657	  	 	$	(51,348	) 	 	 	 	 	 	$	19,381	  	
 	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
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	) 	 	 	 	 	 	 	 	 	
 	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Fiscal Year 2011	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Interest cost	  	 	2,993	  	 	 	 	 	 	 	 	 	 	 	(2,993	) 	 	 	 	 	 	 	 	 	
Actual return on plan assets	  	 	(3,984	) 	 	 	 	 	 	 	3,984	  	 	 	 	 	 	 	 	 	 	 	 	 	
Employer contributions	  	 	 	 	 	 	(3,224	) 	 	 	3,224	  	 	 	 	 	 	 	 	 	 	 	 	 	
Benefit payments	  	 	 	 	 	 	 	 	 	 	(4,097	) 	 	 	4,097	  	 	 	 	 	 	 	 	 	
Investment and other expenses	  	 	(377	) 	 	 	 	 	 	 	 	 	 	 	377	  	 	 	 	 	 	 	 	 	
Difference between actual and expected return on plan assets	  	 	597	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	(597	) 	 	 	 	 	
Anticipated expenses	  	 	246	  	 	 	 	 	 	 	 	 	 	 	(246	) 	 	 	 	 	 	 	 	 	
Actuarial loss	  	 	 	 	 	 	 	 	 	 	 	 	 	 	(3,191	) 	 	 	3,191	  	 	 	 	 	
Amortization of unrecognized net actuarial loss	  	 	2,765	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	(2,765	) 	 	 	 	 	
 	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Annual cost/change	  	$	2,240	  	 	$	(3,224	) 	 	 	3,111	  	 	 	(1,956	) 	 	$	(171	) 	 	 	(171	) 	
 	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Ending balance	  	 	 	 	 	 	 	 	 	$	52,434	  	 	$	(67,878	) 	 	 	 	 	 	$	33,041	  	
 	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Funded status at the end of the year	  	 	 	 	 	 	 	 	 	 	 	 	 	$	(15,444	) 	 	 	 	 	 	 	 	 	

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At September 30, 2011 and 2010, the amounts included on the balance sheet in other long-term liabilities were $15.4 million and $16.6 million, respectively.
The $33.0 million net actuarial loss balance at September 30, 2011 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.

 	  	September 30,	 	
 	  	2011	 	 	2010	 	 	2009	 	
Weighted-Average Assumptions Used in the Measurement of the Partnership’s Benefit Obligation	  	 	 	 	 	 	 	 	 	 	 	 	
Discount rate at year end date	  	 	4.35	%	 	 	4.70	%	 	 	5.40	%	
Expected return on plan assets for the year ended	  	 	7.75	%	 	 	7.75	%	 	 	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, 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 4.70% in 2011, 5.4% in 2010, and 7.6% in 2009. 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, 2011	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Corporate and U.S. government bond fund (1)	  	 	31,876	  	  	 	—  	  	  	 	—  	  	  	 	31,876	  	  	 	61	% 	
U.S. government and agency debt securities (1)	  	 	2,683	  	  	 	—  	  	  	 	—  	  	  	 	2,683	  	  	 	5	% 	
U.S. large-cap equity (1)	  	 	13,262	  	  	 	—  	  	  	 	—  	  	  	 	13,262	  	  	 	25	% 	
International equity (1)	  	 	4,189	  	  	 	—  	  	  	 	—  	  	  	 	4,189	  	  	 	8	% 	
Cash	  	 	424	  	  	 	 	 	  	 	—  	  	  	 	424	  	  	 	1	% 	
 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total	  	 	52,434	  	  	 	—  	  	  	 	—  	  	  	 	52,434	  	  	 	100	% 	

(1)	Represent investments in Vanguard funds that seek to replicate the asset category description.	
Partnership expects to make pension contributions of approximately $3.4 million in fiscal 2012.
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 $21.6 million.
 
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13) Income Taxes
Income tax expense is comprised of the following for the indicated periods (in thousands):

 	  	Years Ended September 30,	 	
 	  	2011	 	  	2010	 	  	2009	 	
Current:	  	 	 	 	  	 	 	 	  	 	 	 	
Federal	  	$	3,216	  	  	$	726	  	  	$	2,068	  	
State	  	 	3,676	  	  	 	1,575	  	  	 	1,690	  	
Deferred	  	 	15,831	  	  	 	13,331	  	  	 	(61,355	) 	
 	  	 	 	 	  	 	 	 	  	 	 	 	
 	  	$	22,723	  	  	$	15,632	  	  	$	(57,597	) 	
 	  	 	 	 	  	 	 	 	  	 	 	 	
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,	 	
 	  	2011	 	  	2010	 	 	2009	 	
Income from continuing operations before taxes	  	$	47,067	  	  	$	43,952	  	 	$	73,441	  	
Tax at Federal statutory rate	  	 	16,473	  	  	 	15,383	  	 	 	25,704	  	
Less impact of Partnership income or loss not subject to federal income taxes	  	 	1,631	  	  	 	1,239	  	 	 	(2,447	) 	
State taxes net of federal benefit	  	 	3,493	  	  	 	3,087	  	 	 	4,319	  	
Permanent Differences	  	 	54	  	  	 	(44	) 	 	 	52	  	
Change in valuation allowance	  	 	672	  	  	 	(3,928	) 	 	 	(86,445	) 	
Change in unrecognized tax benefit and other	  	 	400	  	  	 	(105	) 	 	 	1,220	  	
 	  	 	 	 	  	 	 	 	 	 	 	 	
Provision (benefit) for income taxes per income statement	  	$	22,723	  	  	$	15,632	  	 	$	(57,597	) 	
 	  	 	 	 	  	 	 	 	 	 	 	 	
The components of the net deferred taxes and the related valuation allowance for the years ended September 30, 2011 and September 30, 2010 using current tax rates are as follows (in thousands):

 	  	Years Ended September 30,	 	
 	  	2011	 	 	2010	 	
Deferred Tax Assets:	  	 	 	 	 	 	 	 	
Net operating loss carryforwards	  	$	9,263	  	 	$	19,958	  	
Vacation accrual	  	 	2,687	  	 	 	2,624	  	
Pension accrual	  	 	6,308	  	 	 	6,889	  	
Allowance for bad debts	  	 	4,328	  	 	 	2,909	  	
Fair value of derivative instruments	  	 	3,060	  	 	 	2,016	  	
Insurance accrual	  	 	17,520	  	 	 	15,530	  	
Inventory	  	 	702	  	 	 	968	  	
Alternative minimum tax credit carryforward	  	 	261	  	 	 	3,077	  	
Other, net	  	 	2,523	  	 	 	2,692	  	
 	  	 	 	 	 	 	 	 	
Total deferred tax assets	  	 	46,652	  	 	 	56,663	  	
Valuation allowance	  	 	(672	) 	 	 	—  	  	
 	  	 	 	 	 	 	 	 	
Net deferred tax assets	  	$	45,980	  	 	$	56,663	  	
 	  	 	 	 	 	 	 	 	
Deferred Tax Liabilities:	  	 	 	 	 	 	 	 	
Property and equipment	  	$	1,077	  	 	$	927	  	
Intangibles	  	 	14,102	  	 	 	8,937	  	
 	  	 	 	 	 	 	 	 	
Total deferred tax liabilities	  	$	15,179	  	 	$	9,864	  	
 	  	 	 	 	 	 	 	 	
Net deferred taxes	  	$	30,801	  	 	$	46,799	  	

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As of the calendar tax year ended December 31, 2010, Star Acquisitions, a wholly-owned subsidiary of the Partnership, had an estimated Federal net operating loss carry forward (“NOL”) of approximately $17.5 million. The Federal NOLs, which will expire between 2018 and 2024, are generally available to offset any future taxable income but are also subject to annual limitations on the amount that can be used.
FASB ASC 740-10-05-6 Income Taxes topic, Uncertain Tax Position subtopic (SFAS No. 109 and FIN 48), provides financial statement accounting guidance for uncertainty in income taxes and tax positions taken or expected to be taken in a tax return. At September 30, 2011, we had unrecognized income tax benefits totaling $2.5 million including related accrued interest and penalties of $0.4 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, 2010	  	$	2,234	  	
Additions based on tax positions related to the current year	  	 	197	  	
Additions for tax positions of prior years	  	 	100	  	
Reduction for tax positions of prior years	  	 	—  	  	
Reductions due to lapse in statue of limitations/settlements	  	 	(7	) 	
 	  	 	 	 	
Balance at September 30, 2011	  	 	2,524	  	
 	  	 	 	 	
We believe that the total liability for unrecognized tax benefits will not materially change during the next 12 months ending September 30, 2012. Our continuing practice is to recognize interest and penalties related to income tax matters as a component of income tax expense.
We file U.S. Federal income tax returns and various state and local returns. A number of years may elapse before an uncertain tax position is audited and finally resolved. For our Federal income tax returns we have four tax years subject to examination. In our major state tax jurisdictions of New York, Connecticut, Pennsylvania and New Jersey, we have four, four, five, and five tax years, respectively, that are subject to examination. While it is often difficult to predict the final outcome or the timing of resolution of any particular uncertain tax position, based on our assessment of many factors including past experience and interpretation of tax law, we believe that our provision for income taxes reflect the most probable outcome. This assessment relies on estimates and assumptions and may involve a series of complex judgments about future events.
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, 2011 under operating leases having an initial or remaining non-cancelable term of one year or more are as follows (in thousands):

2012	  	$	11,826	  	
2013	  	 	11,162	  	
2014	  	 	10,050	  	
2015	  	 	8,548	  	
2016	  	 	6,443	  	
Thereafter	  	 	9,920	  	
 	  	 	 	 	
Total future minimum lease payments	  	$	57,949	  	
 	  	 	 	 	
Rent expense for the fiscal years ended September 30, 2011, 2010, and 2009, was $13.8 million, $13.3 million, and $15.8 million, respectively.
 
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15) Supplemental Disclosure of Cash Flow Information

 	  	Years Ended September 30,	 	
(in thousands)	  	2011	 	  	2010	 	 	2009	 	
Cash paid during the period for:	  	 	 	 	  	 	 	 	 	 	 	 	
Income taxes, net	  	$	9,215	  	  	$	2,061	  	 	$	2,091	  	
Interest	  	$	12,994	  	  	$	14,836	  	 	$	18,221	  	
Debt redemption premium	  	$	1,409	  	  	$	854	  	 	$	—  	  	
Non-cash financing activities:	  	 	 	 	  	 	 	 	 	 	 	 	
Increase (decrease) in interest expense—amortization of net debt premium on the 10.25% Senior Notes and debt discount on the 8.875% Senior Notes	  	$	52	  	  	$	(132	) 	 	$	(226	) 	
Decrease in net debt premium attributable to redemption of debt	  	$	247	  	  	$	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.
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 Earnings per Share topic, Master Limited Partnerships subtopic (EITF 03-06):

Basic and Diluted Earnings Per Limited Partner:
(in thousands, except per unit data)	  	Years Ended September 30,	 	 	
 	  	2011	 	  	2010	 	  	2009	 	 	
Net income	  	$	24,344	  	  	$	28,320	  	  	$	131,038	  	 	
Less General Partners’ interest in net income	  	 	115	  	  	 	128	  	  	 	561	  	 	
 	  	 	 	 	  	 	 	 	  	 	 	 	 	
Net income available to limited partners	  	 	24,229	  	  	 	28,192	  	  	 	130,477	  	 	
Less dilutive impact of theoretical distribution of earnings under FASB ASC 260-10-45-60 *	  	 	574	  	  	 	1,258	  	  	 	22,252	  	 	
 	  	 	 	 	  	 	 	 	  	 	 	 	 	
Limited Partner’s interest in net income under FASB ASC 260-10-45-60	  	$	23,655	  	  	$	26,934	  	  	$	108,225	  	 	
 	  	 	 	 	  	 	 	 	  	 	 	 	 	
Per unit data:	  	 	 	 	  	 	 	 	  	 	 	 	 	
Basic and diluted net income available to limited partners	  	$	0.36	  	  	$	0.40	  	  	$	1.72	  	 	
Less dilutive impact of theoretical distribution of earnings under FASB ASC 260-10-45-60 *	  	 	0.01	  	  	 	0.02	  	  	 	0.29	  	 	
 	  	 	 	 	  	 	 	 	  	 	 	 	 	
Limited Partner’s interest in net income under FASB ASC 260-10-45-60	  	$	0.35	  	  	$	0.38	  	  	$	1.43	  	 	
 	  	 	 	 	  	 	 	 	  	 	 	 	 	
Weighted average number of Limited Partner units outstanding	  	 	66,822	  	  	 	70,019	  	  	 	75,738	  	 	

*	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.	
 
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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 50% 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	 	 	 	 	
 	  	Dec. 31,	 	  	Mar. 31,	 	  	Jun. 30,	 	 	Sep. 30,	 	 	 	 	
(in thousands - except per unit data)	  	2010	 	  	2011	 	  	2011	 	 	2011	 	 	Total	 	
Sales	  	$	459,501	  	  	$	731,865	  	  	$	246,772	  	 	$	153,172	  	 	$	1,591,310	  	
Gross profit for product, installation and service	  	 	105,207	  	  	 	166,636	  	  	 	51,633	  	 	 	30,493	  	 	 	353,969	  	
Operating income (loss)	  	 	43,651	  	  	 	87,959	  	  	 	(28,266	) 	 	 	(41,297	) 	 	 	62,047	  	
Income (loss) before income taxes	  	 	37,569	  	  	 	84,149	  	  	 	(30,784	) 	 	 	(43,867	) 	 	 	47,067	  	
Net income (loss)	  	 	20,558	  	  	 	48,681	  	  	 	(18,197	) 	 	 	(26,698	) 	 	 	24,344	  	
Limited Partner interest in net income (loss)	  	 	20,459	  	  	 	48,445	  	  	 	(18,109	) 	 	 	(26,566	) 	 	 	24,229	  	
Net income (loss) per Limited Partner unit:	  	 	 	 	  	 	 	 	  	 	 	 	 	 	 	 	 	 	 	 	
Basic and diluted (a)	  	$	0.26	  	  	$	0.61	  	  	$	(0.27	) 	 	$	(0.40	) 	 	$	0.35	  	
 	 	 	
 	  	Three Months Ended	 	 	 	 	
 	  	Dec. 31,	 	  	Mar. 31,	 	  	Jun. 30,	 	 	Sep. 30,	 	 	 	 	
(in thousands - except per unit data)	  	2009	 	  	2010	 	  	2010	 	 	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	  	

(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
Acquisition
In the first two months of fiscal 2012, the Partnership purchased the customer lists and assets of two home heating oil, propane and diesel dealerships for an aggregate cost of approximately $24.1 million, including working capital of $4.5 million.
Quarterly Distribution Declared
On October 25, 2011, we declared a quarterly distribution of $0.0775 per unit, or $0.31 per unit on an annualized basis, on all common units in respect of the fourth quarter of fiscal 2011 payable on November 14, 2011 to holders of record on November 4, 2011. In accordance with our Partnership Agreement, the amount of distributions in excess of the minimum quarterly distribution of $0.0675, are distributed 90% to the holders of common units and 10% to the holders of the general partner units (until certain distribution levels are met), subject to the management incentive compensation plan. As a result, $5.0 million was paid to the common unit holders, $0.06 million was paid to the general partners and $0.04 million was paid to management pursuant to the management incentive compensation plan.
Credit Expanded Under the Amended and Restated Revolving Credit Facility Agreement
On November 22, 2011, the Partnership, as provided for in its amended and restated asset based revolving credit facility agreement, expanded its borrowing capacity $50 million (for a total of $350 million), to provide additional liquidity for the fiscal 2012 heating season from December 2011 to April 2012.
Common Unit Repurchased and Retired
In accordance with the common unit repurchase program authorized by the Board of Directors on July 19, 2010, the Partnership repurchased and retired 0.4 million common units during the first two months of fiscal 2012.
 
F-25

Table of Contents
Schedule I
STAR GAS PARTNERS, L.P. (PARENT COMPANY)
CONDENSED FINANCIAL INFORMATION OF REGISTRANT

(in thousands)	  	Sept. 30,
2011	 	  	Sept. 30,
2010	 	
Balance Sheets	  	 	 	 	  	 	 	 	
 	 	 	
ASSETS	  	 	 	 	  	 	 	 	
Current assets	  	 	 	 	  	 	 	 	
Cash and cash equivalents	  	$	294	  	  	$	230	  	
Prepaid expenses and other current assets	  	 	522	  	  	 	1,039	  	
 	  	 	 	 	  	 	 	 	
Total current assets	  	 	816	  	  	 	1,269	  	
 	  	 	 	 	  	 	 	 	
Investment in subsidiaries (a)	  	 	400,048	  	  	 	365,592	  	
Deferred charges and other assets, net	  	 	3,328	  	  	 	589	  	
 	  	 	 	 	  	 	 	 	
Total Assets	  	$	404,192	  	  	$	367,450	  	
 	  	 	 	 	  	 	 	 	
LIABILITIES AND PARTNERS’ CAPITAL	  	 	 	 	  	 	 	 	
Current liabilities	  	 	 	 	  	 	 	 	
Accrued expenses	  	$	4,969	  	  	$	2,300	  	
 	  	 	 	 	  	 	 	 	
Total current liabilities	  	 	4,969	  	  	 	2,300	  	
 	  	 	 	 	  	 	 	 	
Long-term debt (b)	  	 	124,263	  	  	 	82,770	  	
Other long-term liabilities	  	 	2,327	  	  	 	2,469	  	
Partners’ capital	  	 	272,633	  	  	 	279,911	  	
 	  	 	 	 	  	 	 	 	
Total Liabilities and Partners’ Capital	  	$	404,192	  	  	$	367,450	  	

(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: 2012—$0; 2013—$0; 2014—$0; 2015—$0; 2016—$0; thereafter —$125,000 8.875% Senior Notes maturing in December 2017. In December 2010, the 10.25% Senior Notes due February 2013, were redeemed.	
 
F-26

Table of Contents
STAR GAS PARTNERS, L.P. (PARENT COMPANY)
CONDENSED FINANCIAL INFORMATION OF REGISTRANT

 	  	Years Ended September 30,	 	
(in thousands)	  	2011	 	 	2010	 	 	2009	 	
Statements of Operations	  	 	 	 	 	 	 	 	 	 	 	 	
Revenues	  	$	—  	  	 	$	—  	  	 	$	—  	  	
General and administrative expenses	  	 	2,026	  	 	 	2,231	  	 	 	2,592	  	
 	  	 	 	 	 	 	 	 	 	 	 	 	
Operating loss	  	 	(2,026	) 	 	 	(2,231	) 	 	 	(2,592	) 	
Net interest expense	  	 	(11,638	) 	 	 	(10,299	) 	 	 	(14,800	) 	
Amortization of debt issuance costs	  	 	(501	) 	 	 	(336	) 	 	 	(444	) 	
Gain (loss) on redemption of debt	  	 	(1,700	) 	 	 	(1,132	) 	 	 	9,706	  	
 	  	 	 	 	 	 	 	 	 	 	 	 	
Net loss before equity income	  	 	(15,865	) 	 	 	(13,998	) 	 	 	(8,130	) 	
Equity income of Star Petro Inc. and subs	  	 	40,209	  	 	 	42,426	  	 	 	139,168	  	
 	  	 	 	 	 	 	 	 	 	 	 	 	
Net income	  	$	24,344	  	 	$	28,428	  	 	$	131,038	  	

F-27

Table of Contents
STAR GAS PARTNERS, L.P. (PARENT COMPANY)
CONDENSED FINANCIAL INFORMATION OF REGISTRANT

 	  	Years Ended September 30,	 	
(in thousands)	  	2011	 	 	2010	 	 	2009	 	
Statements of Cash Flows	  	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	
Cash flows provided by (used in) operating activities:	  	 	 	 	 	 	 	 	 	 	 	 	
Net cash provided by (used in) operating activities (a)	  	$	(4,813	) 	 	$	104,625	  	 	$	48,013	  	

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	  	 	(82,499	) 	 	 	(50,854	) 	 	 	(30,230	) 	
Proceeds from the issuance of debt	  	 	124,188	  	 	 	—  	  	 	 	—  	  	
Debt extinguishment costs	  	 	(1,409	) 	 	 	—  	  	 	 	—  	  	
Distributions	  	 	(20,677	) 	 	 	(20,353	) 	 	 	(15,411	) 	
Unit repurchase	  	 	(10,949	) 	 	 	(33,234	) 	 	 	(2,336	) 	
Increase in deferred charges	  	 	(3,777	) 	 	 	—  	  	 	 	—  	  	
 	  	 	 	 	 	 	 	 	 	 	 	 	
Net cash provided by (used in) financing activities	  	 	4,877	  	 	 	(104,441	) 	 	 	(47,977	) 	
 	  	 	 	 	 	 	 	 	 	 	 	 	
Net increase in cash	  	 	64	  	 	 	184	  	 	 	36	  	
Cash and cash equivalents at beginning of period	  	 	230	  	 	 	46	  	 	 	10	  	
 	  	 	 	 	 	 	 	 	 	 	 	 	
Cash and cash equivalents at end of period	  	$	294	  	 	$	230	  	 	$	46	  	

 	  	 	 	 	 	 	 	 	 	 	 	 	
(a) Includes distributions from subsidiaries	  	$	32,579	  	 	$	117,310	  	 	$	65,164	  	

F-28

Table of Contents
Schedule II
STAR GAS PARTNERS, L.P. AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS
Years Ended September 30, 2011, 2010 and 2009
(in thousands)

Year	  	Description	  	Balance at
Beginning
of Year	 	  	Charged
to Costs  &
Expenses	 	  	Other
Changes
Add (Deduct)	 	 	Balance at
End of  Year	 	
2011	  	Allowance for doubtful accounts	  	$	5,443	  	  	$	10,388	  	  	$	(6,301	) (a) 	 	$	9,530	  	
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	  	

(a) 	Bad debts written off (net of recoveries).	
 
F-29

Exhibit 10.20
FIRST AMENDMENT
FIRST AMENDMENT, dated as of November 22, 2011 (this “Amendment”), to the Amended and Restated Credit Agreement, dated as of June 3, 2011 (as further amended, amended and restated, supplemented or otherwise modified from time to time, the “ Credit Agreement ”), among Petroleum Heat and Power Co., Inc., a Minnesota corporation (the “ Borrower ”), the other Loan Parties, the Lenders from time to time party hereto, JPMorgan Chase Bank, N.A., a national banking association, as an LC Issuer and as the Agent (in its capacity as the Agent, the “ Administrative Agent ”), Bank of America, N.A., as Syndication Agent and as an LC Issuer, RBS Citizens, N.A., as Documentation Agent, and Key Bank National Association, PNC Bank, N.A., Regions Bank, TD Bank, N.A. and Wells Fargo Capital Finance, as Senior Managing Agents. J.P. Morgan Securities LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated and RBS Citizens, N.A. are acting as joint lead arrangers and joint bookrunners (in such capacities, the “ Arrangers ”) in connection with this Amendment and the Increased Aggregate Commitment referred to below.
WITNESSETH
WHEREAS, pursuant to the Credit Agreement, the Lenders have agreed to make, and have made, certain loans and other extensions of credit to the Borrower;
WHEREAS, pursuant to Section 2.16 of the Credit Agreement, the Borrower has requested that the Aggregate Commitment be increased by an aggregate amount of $50,000,000 (the “ Increased Aggregate Commitment ”), and each Lender with an “Increased Commitment” amount set forth opposite its name on  Schedule I  hereto (each such Lender, an “ Incremental Lender ”) has severally agreed, upon the terms and subject to the conditions set forth herein, to provide the Increased Aggregate Commitment;
WHEREAS, the Borrower has further requested that the Credit Agreement be amended as set forth herein; and
WHEREAS, the Required Lenders are willing to agree to this Amendment on the terms set forth herein.
NOW, THEREFORE, in consideration of the premises and mutual covenants contained herein, the parties hereto agree as follows:
1 Capitalized Terms. Capitalized terms used but not defined herein shall have the meanings assigned to such terms in the Credit Agreement.
2 Increased Aggregate Commitment. Subject to the terms and conditions set forth herein, on the Amendment Effective Date (as defined below) each Incremental Lender severally agrees to increase its existing Commitment by an amount equal to the amount set forth under the heading “Increased Commitment” opposite such Incremental Lender’s name on Schedule I hereto, such that its total Commitment as of the Amendment Effective Date shall be the amount set forth under the heading “Total Commitment” opposite such Lender’s name on Schedule I hereto. On the Amendment Effective Date, Schedule I to the Credit Agreement shall be replaced in its entirety by the schedule set forth on Annex I hereto.
3 Amendments
3.1 . The Credit Agreement shall be amended as of the Amendment Effective Date (as defined below) as set forth below.
Amendments to Section 1.1 (Defined Terms). Section 1.1 of the Credit Agreement is hereby amended as follows:
by amending the definition of “Aggregate Commitment” by deleting the amount “$300,000,000” in the third line thereof and replacing it with “$350,000,000”.
by amending the definition of “Capital Expenditures” by inserting the parenthetical phrase “(other than pursuant to an Acquisition)” immediately after the words “acquisition of any asset” in the second line thereof.
by inserting the following definition in proper alphabetical order:
“First Amendment” means the First Amendment to this Agreement dated November 22, 2011.

by amending the definition of “Loan Documents” by adding “the First Amendment,” immediately after “this Agreement,” in the first line thereof.
by amending and restating the definition of “Non-Seasonal Availability Amount” as follows:
“Non-Seasonal Availability Amount” means $250,000,000; provided that, if the Aggregate Commitment is increased pursuant to Section 2.16 hereof, the Non-Seasonal Availability Amount shall (if the Borrower so elects on the effective date of any such increase) be deemed to be an amount equal to the Non-Seasonal Availability Amount in effect immediately prior to such increase plus an amount equal to up to the aggregate amount of such increase and all prior increases in Commitments (to the extent such increased Commitments have not since been terminated or reduced in accordance with this Agreement) made pursuant to Section 2.16.
by amending the definition of “Permitted Acquisition” by inserting the following parenthetical phrase immediately after the word “Availability” in the fourth line of clause (l) thereof:
3.1.1 “(with any Suppressed Availability being included in each calculation of Availability pursuant to this clause (l))”
by amending the definition of “Fixed Charge Coverage Ratio” by inserting the following parenthetical phrase immediately after the words “Consolidated Capital Expenditures” in the third line thereof:
“(excluding, for each such period, actual Capital Expenditures in respect of propane tanks in an amount not to exceed $4,500,000)”
Amendment to Section 2.16 (Termination of the Commitments; Increase in Aggregate Commitment). Section 2.16 of the Credit Agreement is hereby amended by deleting the amount “$400,000,000” in the fifth line of clause (c) thereof and replacing it with “$450,000,000”.
Amendment to Section 6.27 (Capital Expenditures). Section 6.27 of the Credit Agreement is hereby amended and restated in its entirety as follows:
3.2 “6.27 Capital Expenditures. The Loan Parties shall not expend, or be committed to expend, (a) in excess of $7,500,000 for Capital Expenditures (other than Capital Expenditures in respect of propane tanks, which shall be governed by clause (b) of this Section 6.27) during any Fiscal Year in the aggregate for the Parent and its Subsidiaries or (b) in excess of $4,500,000 for Capital Expenditures in respect of propane tanks during any Fiscal Year in the aggregate for the Parent and its Subsidiaries;  provided, however,  that the amount of permitted Capital Expenditures under clause (a) only will be increased in any Fiscal Year by the amount, if positive, equal to 50% of the difference between the Capital Expenditures limit specified in clause (a) above  minus  the actual amount of any Capital Expenditures expended pursuant to clause (a) during the prior Fiscal Year (the “ Carry Over Amount ”). Any Carry Over Amount may only be carried over to the next succeeding year.”
4 Conditions to Effectiveness of Amendment. This Amendment shall become effective on the date on which the following conditions precedent have been satisfied or waived (the “ Amendment Effective Date ”):

The Administrative Agent shall have received a counterpart of this Amendment, executed and delivered by a duly authorized officer of each of (i) the Loan Parties, (ii) the Incremental Lenders and (iii) the Required Lenders.
The Administrative Agent shall have received (i) a certificate (with appropriate insertions and attachments) of each Loan Party signed by an authorized officer of such Loan Party and, among other things (i) certifying and attaching the resolutions adopted by such Loan Party approving or consenting to this Amendment and the increase in the Aggregate Commitment to be effected hereby and (ii) in the case of the Borrower, certifying that, before and after giving effect to such increase, (x) the representations and warranties contained in the Credit Agreement and the other Loan Documents are true and correct (except to the extent that such representations and warranties specifically refer to an earlier date, in which case they are true and correct as of such earlier date) and (y) no Default or Unmatured Default exists, and (ii) legal opinions in such form and substance as the Administrative Agent may reasonably request.
The Administrative Agent shall have received an instrument of acknowledgement and confirmation, substantially in the form of Exhibit A  hereto and signed by an authorized officer of each Loan Party, with respect to the guarantees, security interests and liens created under the Loan Documents and the effectiveness and enforceability thereof for the benefit of all Lenders (including the Incremental Lenders) after giving effect to this Amendment.
The Arrangers, the Administrative Agent and the Incremental Lenders shall have received all fees required to be paid, and all reasonable out-of-pocket expenses for which invoices have been presented (including, without limitation, the reasonable fees and disbursements of legal counsel), on or before the Amendment Effective Date.
5 Representations and Warranties. Each Loan Party hereby represents and warrants that (a) each of the representations and warranties contained in Article V of the Credit Agreement are, after giving effect to this Amendment, true and correct in all material respects as if made on and as of the Amendment Effective Date (unless such representations and warranties are stated to relate to a specific earlier date, in which case such representations and warranties shall be true and correct in all material respects as of such earlier date); provided, that each reference to the Credit Agreement therein shall be deemed to be a reference to the Credit Agreement after giving effect to this Amendment and (b) after giving effect to this Amendment and the Increased Aggregate Commitment, no Default or Unmatured Default has occurred and is continuing.
6 Effects on Credit Documents. (a) Except as specifically amended herein, all Loan Documents shall continue to be in full force and effect and are hereby in all respects ratified and confirmed.
The execution, delivery and effectiveness of this Amendment shall not operate as a waiver of any right, power or remedy of any Lender or the Administrative Agent under any of the Loan Documents, nor constitute a waiver of any provision of the Loan Documents.
7 Expenses. The Borrower agrees to pay and reimburse the Arrangers and the Administrative Agent for all of their reasonable out-of-pocket costs and expenses incurred in connection with the preparation and delivery of this Amendment, and any other documents prepared in connection herewith and the transactions contemplated hereby, including, without limitation, the reasonable fees and disbursements of legal counsel.
8 GOVERNING LAW; WAIVER OF JURY TRIAL. THIS AMENDMENT AND THE RIGHTS AND OBLIGATIONS OF THE PARTIES HEREUNDER SHALL BE CONSTRUED IN ACCORDANCE WITH AND BE GOVERNED BY THE LAW OF THE STATE OF NEW YORK. EACH PARTY HERETO HEREBY AGREES AS SET FORTH FURTHER IN SECTIONS 16.2 AND 16.3 OF THE CREDIT AGREEMENT AS IF SUCH SECTIONS WERE SET FORTH IN FULL HEREIN.
9 Amendments; Execution in Counterparts. (b) This Amendment shall not constitute an amendment of any other provision of the Credit Agreement not referred to herein and shall not be construed as a waiver or consent to any further or future action on the part of the Loan Parties that would require a waiver or consent of the Required Lenders or the Administrative Agent. Except as expressly amended hereby, the provisions of the Credit Agreement are and shall remain in full force and effect.
This Amendment may not be amended nor may any provision hereof be waived except pursuant to a writing signed by the Loan Parties, the Administrative Agent and the Required Lenders. This Amendment may be executed in any number of counterparts and by the different parties hereto on separate counterparts, including by means of facsimile or electronic transmission, each of which when so executed and delivered shall be an original, but all of which shall together constitute one and the same instrument.
[Remainder of page intentionally left blank]

IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be duly executed and delivered by their respective proper and duly authorized officers as of the day and year first above written.

BORROWER:
 
PETROLEUM HEAT AND POWER CO., INC.	
 	 	
By:	 	 	
 	 	
Name: 	 	 	
 	 	
Title:	 	 	
 	
OTHER LOAN PARTIES:	
 	
A.P. WOODSON COMPANY	
C. HOFFBERGER COMPANY	
CHAMPION ENERGY CORPORATION	
CHAMPION OIL COMPANY	
COLUMBIA PETROLEUM TRANSPORTATION, LLC	
HOFFMAN FUEL COMPANY OF BRIDGEPORT	
HOFFMAN FUEL COMPANY OF DANBURY	
HOFFMAN FUEL COMPANY OF STAMFORD	
J.J. SKELTON OIL COMPANY	
LEWIS OIL COMPANY	
MAREX CORPORATION	
MEENAN HOLDINGS OF NEW YORK, INC.	
MEENAN OIL CO., INC.	
MINNWHALE LLC	
ORTEP OF PENNSYLVANIA, INC.	
PETRO HOLDINGS, INC.	
PETRO PLUMBING CORPORATION PETRO, INC.	
REGIONOIL PLUMBING, HEATING AND COOLING CO., INC.	
RICHLAND PARTNERS, LLC	
RYE FUEL COMPANY	
STAR ACQUISITIONS, INC.	
STAR GAS FINANCE COMPANY	
TG&E SERVICE COMPANY, INC.	
 	 	
By:	 	 	
 	 	
Name: 	 	 	
 	 	
Title:	 	 	
 
STAR GAS PARTNERS, L.P.
 
By: KESTREL HEAT, LLC, its General Partner	
 	 	
By:	 	 	
 	 	
Name:	 	 	
 	 	
Title:	 	 	

 	 	 	
MEENAN OIL CO., L.P.	
 	
By: MEENAN OIL CO., INC., its General Partner	

By:	 	 	

Name: 	 	 	

Title: 	 	 	

CFS LLC	
 	
By: Richland Partners, LLC, its Sole Member	

By:	 	 	

Name: 	 	 	

Title: 	 	 	

 	 	JPMORGAN CHASE BANK, N.A., as Administrative Agent as a Lender	
 	 	 	
 	 	By: 	 	 	
 	 	Name:	 	 	
 	 	Title:	 	 	

 	 	[            ], as [an Incremental Lender] [a Lender]	
 	 	 	
 	 	By: 	 	 	
 	 	Name:	 	 	
 	 	Title:	 	 	

SCHEDULE I

Name of Incremental Lender	  	Existing Commitment	 	  	Increased Commitment	 	  	Total Commitment	 	
JPMorgan Chase Bank, N.A.	  	$	44,000,000	  	  	$	3,850,000	  	  	$	47,850,000	  	
Bank of America, N.A.	  	$	44,000,000	  	  	$	3,550,000	  	  	$	47,550,000	  	
RBS Citizens, N.A.	  	$	44,000,000	  	  	$	3,550,000	  	  	$	47,550,000	  	
Citibank, N.A.	  	$	7,500,000	  	  	$	3,550,000	  	  	$	11,050,000	  	
BMO Harris Bank, N.A.	  	$	7,000,000	  	  	$	3,550,000	  	  	$	10,550,000	  	
Israel Discount Bank of New York	  	$	10,000,000	  	  	$	3,550,000	  	  	$	13,550,000	  	
Keybank National Association	  	$	20,000,000	  	  	$	3,550,000	  	  	$	23,550,000	  	
PNC Bank, N.A.	  	$	20,000,000	  	  	$	3,550,000	  	  	$	23,550,000	  	
RB International Finance (USA) LLC	  	$	8,000,000	  	  	$	0	  	  	$	8,000,000	  	
Regions Bank	  	$	20,000,000	  	  	$	3,550,000	  	  	$	23,550,000	  	
Societe Generale	  	$	18,500,000	  	  	$	3,550,000	  	  	$	22,050,000	  	
Sovereign Bank	  	$	12,000,000	  	  	$	3,550,000	  	  	$	15,550,000	  	
TD Bank, N.A.	  	$	20,000,000	  	  	$	3,550,000	  	  	$	23,550,000	  	
Webster Bank, N.A.	  	$	5,000,000	  	  	$	3,550,000	  	  	$	8,550,000	  	
Wells Fargo Bank, N.A.	  	$	20,000,000	  	  	$	3,550,000	  	  	$	23,550,000	  	
Total:	  	$	300,000,000	  	  	$	50,000,000	  	  	$	350,000,000	  	

ANNEX I

Name of Lender	  	Commitment	 	
JPMorgan Chase Bank, N.A.	  	$	47,850,000	  	
Bank of America, N.A.	  	$	47,550,000	  	
RBS Citizens, N.A.	  	$	47,550,000	  	
Citibank, N.A.	  	$	11,050,000	  	
BMO Harris Bank, N.A.	  	$	10,550,000	  	
Israel Discount Bank of New York	  	$	13,550,000	  	
Keybank National Association	  	$	23,550,000	  	
PNC Bank, N.A.	  	$	23,550,000	  	
RB International Finance (USA) LLC	  	$	8,000,000	  	
Regions Bank	  	$	23,550,000	  	
Societe Generale	  	$	22,050,000	  	
Sovereign Bank	  	$	15,550,000	  	
TD Bank, N.A.	  	$	23,550,000	  	
Webster Bank, N.A.	  	$	8,550,000	  	
Wells Fargo Bank, N.A.	  	$	23,550,000	  	
Total:	  	$	350,000,000	  	

EXHIBIT A
ACKNOWLEDGMENT AND CONFIRMATION
Dated as of November 22, 2011
1. Reference is made to the First Amendment, dated as of November 22, 2011 (the “First Amendment”), to the Amended and Restated Credit Agreement, dated as of June 3, 2011 (as amended, amended and restated, supplemented or otherwise modified from time to time, the “ Credit Agreement ”), among Petroleum Heat and Power Co., Inc., a Minnesota corporation (the “ Borrower ”), the other Loan Parties, the Lenders from time to time party hereto, JPMorgan Chase Bank, N.A., a national banking association, as an LC Issuer and as the Agent (in its capacity as the Agent, the “ Administrative Agent ”), Bank of America, N.A., as Syndication Agent and as an LC Issuer, RBS Citizens, N.A., as Documentation Agent, and Key Bank National Association, PNC Bank, N.A., Regions Bank, TD Bank, N.A. and Wells Fargo Capital Finance, as Senior Managing Agents. Capitalized terms used but not defined in this Acknowledgment and Confirmation (this “ Acknowledgment and Confirmation ”) shall have the meanings assigned to such terms in the Credit Agreement or the First Amendment, as the case may be.
2. It is a condition to the effectiveness of the First Amendment that the Borrower and the other Loan Parties shall have executed this Acknowledgment and Confirmation with respect to the guarantees, security interests and Liens created under the Loan Documents and the effectiveness and enforceability thereof for the benefit of the Lenders (including the Incremental Lenders). Accordingly, each of the Loan Parties party hereto hereby agrees, with respect to each Loan Document to which it is a party, that:
(a) all of its obligations (including in respect of the Guaranteed Obligations) under each such Loan Document shall remain in full force and effect on a continuous basis after giving effect to the First Amendment and this Acknowledgment and Confirmation, it being understood and agreed that such obligations include its obligations with respect to the Increased Aggregate Commitment after giving effect to the First Amendment; and
(b) all of the Liens and security interests created and arising under each such Loan Document remain in full force and effect on a continuous basis, and the perfected status and priority of each such Lien and security interest continues in full force and effect on a continuous basis, unimpaired, uninterrupted and undischarged, after giving effect to the First Amendment and this Acknowledgment and Confirmation, as collateral security for its obligations under the Loan Documents.
3. THIS ACKNOWLEDGMENT AND CONFIRMATION SHALL BE GOVERNED BY, AND CONSTRUED AND INTERPRETED IN ACCORDANCE WITH, THE LAW OF THE STATE OF NEW YORK.
4. This Acknowledgment and Confirmation may be executed by one or more of the parties hereto on any number of separate counterparts (including by telecopy or electronic mail), and all of said counterparts taken together shall be deemed to constitute one and the same instrument. By executing and delivering this Acknowledgment and Confirmation, each party hereto hereby acknowledges and agrees that it is both a Guarantor and a Grantor as such terms are defined in the Credit Agreement and Security Agreement, respectively (including with respect to the Increased Aggregate Commitment) and agrees that it will be bound thereby.
[remainder of page intentionally left blank]

IN WITNESS WHEREOF, the parties hereto have caused this Acknowledgment and Confirmation to be duly executed and delivered by their proper and duly authorized officers as of the day and year first above written.

BORROWER:
 
PETROLEUM HEAT AND POWER CO., INC.	
 	 	
By:    	 	 	
Name: 	 	 	
Title:	 	 	

OTHER LOAN PARTIES:
 
A.P. WOODSON COMPANY
C. HOFFBERGER COMPANY
CHAMPION ENERGY CORPORATION
CHAMPION OIL COMPANY
COLUMBIA PETROLEUM TRANSPORTATION, LLC
HOFFMAN FUEL COMPANY OF BRIDGEPORT
HOFFMAN FUEL COMPANY OF DANBURY
HOFFMAN FUEL COMPANY OF STAMFORD
J.J. SKELTON OIL COMPANY
LEWIS OIL COMPANY
MAREX CORPORATION
MEENAN HOLDINGS OF NEW YORK, INC.
MEENAN OIL CO., INC.
MINNWHALE LLC
ORTEP OF PENNSYLVANIA, INC.
PETRO HOLDINGS, INC.
PETRO PLUMBING CORPORATION PETRO, INC.
REGIONOIL PLUMBING, HEATING AND COOLING CO., INC.
RICHLAND PARTNERS, LLC
RYE FUEL COMPANY
STAR ACQUISITIONS, INC.
STAR GAS FINANCE COMPANY
TG&E SERVICE COMPANY, INC.	
 	 	
By:	 	 	
Name: 	 	 	
Title: 	 	 	

STAR GAS PARTNERS, L.P.
 
By: KESTREL HEAT, LLC, its General Partner	
 	 	
By: 	 	 	
Name: 	 	 	
Title: 	 	 	

 	 	 	
MEENAN OIL CO., L.P.
 
By: MEENAN OIL CO., INC., its General Partner	
 	 	
By:	 	 	
Name: 	 	 	
Title: 	 	 	

CFS LLC
 
By:  Richland Partners, LLC, its Sole Member	
 	 	
By:	 	 	
Name: 	 	 	
Title: 	 	 	

Exhibit 21
Partnership Subsidiaries
A.P. Woodson Company—District of Columbia
C. Hoffberger Company —Maryland
Champion Energy Corporation—Delaware
Champion Oil Company —Connecticut
Columbia Petroleum Transportation, LLC—Delaware
Hoffman Fuel Company of Bridgeport —Delaware
Hoffman Fuel Company of Danbury—Delaware
Hoffman Fuel Company of Stamford —Delaware
J.J. Skelton Oil Company —Pennsylvania
Lewis Oil Company, Inc. —New York
Marex Corporation—Maryland
Meenan Holdings of New York, Inc.—New York
Meenan Oil Co., Inc.—Delaware
Meenan Oil Co., L.P.—Delaware
Minnwhale, LLC .—New York
Ortep of Pennsylvania, Inc.—Pennsylvania
Petro Holdings, Inc.—Minnesota
Petro Plumbing Corporation—New Jersey
Petro, Inc.—Delaware
Petroleum Heat and Power Co., Inc.—Minnesota
RegionOil Plumbing, Heating and Cooling Co., Inc.—New Jersey
Richland Partners, LLC—Pennsylvania
Rye Fuel Company —Delaware
Star Gas Finance Company—Delaware
Star Acquisitions, Inc.—Minnesota
TG&E Service Company, Inc.—Florida

Exhibit 23.1
Consent of Independent Registered Public Accounting Firm
The Partners
of Star Gas Partners, L.P.:
We consent to the incorporation by reference in the registration statement (No. 333-175247) on Form S-3 of Star Gas Partners, L.P. of our report dated December 7, 2011, with respect to the consolidated balance sheets of Star Gas Partners, L.P. (“the Partnership”) as of September 30, 2011 and 2010, 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, 2011, the related financial statement schedules, and the effectiveness of internal control over financial reporting as of September, 30, 2011, which report appears in the September 30, 2011 annual report on Form 10-K of Star Gas Partners, L.P.
Stamford, Connecticut
December 7, 2011

Exhibit 31.1
CERTIFICATIONS
I, Daniel P. Donovan, certify that:
 
1.	I have reviewed this annual report on Form 10-K of Star Gas Partners, L.P. (“Registrant”);	
 
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;	
 
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;	
 
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal controls over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:	
 
 	(a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;	
 
 	(b)	designed such internal controls over financial reporting, or caused such internal controls over financial reporting to be designed under our supervision, 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;	
 
 	(c)	evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and	
 
 	(d)	disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and	
 
5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):	
 
 	(a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information and;	
 
 	(b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.	
Date: December 7, 2011

/s/ Daniel P. Donovan	
Daniel P. Donovan	
President and Chief Executive Officer	
Star Gas Partners, L.P.	

Exhibit 31.2
CERTIFICATIONS
I, Richard F. Ambury, certify that:
 
1.	I have reviewed this annual report on Form 10-K of Star Gas Partners, L.P. (“Registrant”);	
 
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;	
 
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;	
 
4.	The registrants’ other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal controls over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:	
 
 	(a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;	
 
 	(b)	designed such internal controls over financial reporting, or caused such internal controls over financial reporting to be designed under our supervision, 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;	
 
 	(c)	evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and	
 
 	(d)	disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and	
 
5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):	
 
 	(c)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information and;	
 
 	(d)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.	
Date: December 7, 2011

/s/ RICHARD F. AMBURY	
Richard F. Ambury
Chief Financial Officer
Star Gas Partners, L.P.	

Exhibit 32.1
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350
AS ADOPTED PURSUANT TO SECTION 906
OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Annual Report of Star Gas Partners, L.P. (the “Partnership”) on Form 10-K for the year ended September 30, 2011 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Daniel P. Donovan, President and Chief Executive Officer of the Partnership, certify to my knowledge pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, following due inquiry, I believe that:
 
 	(1)	The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and	
 
 	(2)	The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Partnership.	
A signed original of this written statement required by Section 906 has been provided to Star Gas Partners, L.P. and will be retained by Star Gas Partners, L.P. and furnished to the Securities and Exchange Commission or its staff upon request.

 	 	 	 	STAR GAS PARTNERS, L.P.
By: KESTREL HEAT, LLC (General Partner)	
 	 	 	 	
Date: December 7, 2011	 	 	 	By:	 	/s/ Daniel P. Donovan	
 	 	 	 	 	 	 	 	Daniel P. Donovan
President and Chief Executive Officer
Star Gas Partners, L.P.	

Exhibit 32.2
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Annual Report of Star Gas Partners, L.P. (the “Partnership”) on Form 10-K for the year ended September 30, 2011 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Richard F. Ambury, Chief Financial Officer of the Partnership, certify to my knowledge pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, following due inquiry, I believe that:
 
 	(1)	The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and	
 
 	(2)	The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Partnership.	
A signed original of this written statement required by Section 906 has been provided to Star Gas Partners, L.P. and will be retained by Star Gas Partners, L.P. and furnished to the Securities and Exchange Commission or its staff upon request.

 	 	 	 	STAR GAS PARTNERS, L.P.
By: KESTREL HEAT, LLC (General Partner)	
 	 	 	 	
Date: December 7, 2011	 	 	 	By:	 	/s/ RICHARD F. AMBURY	
 	 	 	 	 	 	 	 	Richard F. Ambury
Chief Financial Officer
Star Gas Partners, L.P.